SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT 

DraftFinal Staff Report Further Reductions of VOC 

Proposed Rule 1178 Emissions From Storage Tanks 

(Previously PR1173.1) At Petroleum Facilities 

December 11,October 26, 2001 

Deputy Executive Officer 

Planning, Rule Development, and Area Sources 

Elaine Chang, DrPH 

Assistant Deputy Executive Officer 

Planning, Rule Development, and Area Sources 

Laki Tisopulos, Ph.D., P.E. 

Authors 

Minh Pham, P.E. – Air Quality Engineer 

Eugene Teszler – Air Quality Engineer 

Kennard Ellis – Air Quality Engineer 

Reviewed By 

Ed Muehlbacher, P.E. – Program Supervisor 

Frances Keeler – Senior Deputy District Counsel 

Contributors 

Jay Chen, P.E. – Senior Air Quality Engineering Manager 

Roger Christopher – Supervisor Air Quality Inspector 

Mike Garibay, P.E. – Senior Air Quality Engineer 

Xuan Vu, P.E. – Senior Air Quality Engineer 

Wayne Stredwick – Assistant Air Quality Engineer 

Mei Wang – Assistant Air Quality Engineer 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT 

GOVERNING BOARD 

Chairman: WILLIAM A. BURKE, Ed.D 

Speaker of the Assembly Appointee 

Vice Chairman: NORMA J. GLOVER 

Council Member, Newport Beach 

Cities Representative, County of Orange 

 MEMBERS:

 MICHAEL D. ANTONOVICH 

 Supervisor, Fifth District 

 Los Angeles County Representative 

HAL BERNSON 

 Council Member, City of Los Angeles 

 Cities Representative, Los Angeles County/Western Region 

 JANE W. CARNEY 

 Senate Rules Committee Appointee 

 BEATRICE J. S. LAPISTO-KIRTLEY 

 Council Member, City of Bradbury 

 Cities Representative, Los Angeles County/Eastern Region 

RONALD O. LOVERIDGE 

 Mayor, City of Riverside 

 Cities Representative, Riverside County 

 JON D. MIKELS 

 Supervisor, Second District 

 San Bernardino County Representative

 LEONARD PAULITZ 

 Mayor Pro Tem, City of Montclair 

 Cities Representative, San Bernardino County 

 JAMES W. SILVA 

 Supervisor, Second District 

 Orange County Representative 

CYNTHIA VERDUGO-PERALTA

Governor’s Appointee 

 S. ROY WILSON, Ed.D. 

 Supervisor, Fourth District 

 Riverside County Representative 

EXECUTIVE OFFICER

 BARRY R. WALLERSTEIN, D.Env. 
Acknowledgments

District staff would like to acknowledge the contribution of the following individuals in 

developing the Proposed Rule 1178. While the Proposed Rule 1178 and Staff Report may not 

reflect the opinion of any individual, many recommendations of the following members are 

incorporated in the proposed rule. The time commitment and contribution of each individual are 

appreciated. 

Joan Niertit and her team SCAQMD

Michael Czap and his team SCAQMD

Erik White ARB

Susan Livingston BPArco

Marcelo Panelo BPArco

Joe Prawdzik BPArco

Maryann Gonzalez BPArco

Ryan Rietzel BPArco

Gordon Schremp California Energy Commission

Mike Barranco Cenco Refining

Michelle Gablich Chevron Products Co.

Dennis Leonard Chevron Products Co.

Rod Spackman Chevron Products Co.

Hector Villegas Conservatek

Amy Gannon Davenport (for Ultramar Inc.)

Royann Winchester Equilon Enterprises, LLC

Stan Holm Exxon Mobil

Jerry Engelhardt Kinder Morgan (GATX)

Connie More Kinder Morgan (GATX) 

Larry Kippes Kinder Morgan (GATX)

Doug Thompson Paramount Petroleum

Miles Heller Phillips Tosco

Brian Christlieb Phillips Tosco

Scott Zerga Phillips Tosco

Dave Hackett Stillwater Associates

Thomas Gieskes Stillwater Associates

George Morovich Temcor

Rob Ferry The TGB Partnership

George Gavlik Ultraflote

James Hatchell Ultramar Inc.

Craig Moyer Western Independent Refiners Association

Ron Wilkniss Western States Petroleum Association

Mike Wang Western States Petroleum Association
Table of Contents Final Staff Report

Proposed Rule 1178 December 11, 2001 i

TABLE OF CONTENTS 

Executive Summary....................................................................................................................1 

Chapter 1 – Background ............................................................................................................1 

Legislative Authority .................................................................................................................................... 1 

AQMP Control Measures ............................................................................................................................ 1 

District Rules ................................................................................................................................................. 2 

Development Process of Proposed Rule 1178 ........................................................................................... 2 

Affected Industries ........................................................................................................................................ 3 

Chapter 2 – Emissions Inventory ...............................................................................................5 

Chapter 3 – Control Technology .............................................................................................. 10 

Rim Seal Systems ........................................................................................................................................ 10 

Deck Fittings ................................................................................................................................................ 10 

Domed External Floating Roof Tanks ..................................................................................................... 11 

Internal Floating Roof Tanks.................................................................................................................... 12 

Vapor Recovery or Vapor Control Systems ........................................................................................... 12 

Pressure Vacuum Vents ............................................................................................................................. 12 

Chapter 4 – Proposed Rule 1178 .............................................................................................. 13 

Applicability................................................................................................................................................. 13 

Definitions .................................................................................................................................................... 13 

Requirements ............................................................................................................................................... 13 

Other Requirements ................................................................................................................................... 15

Chapter 5 – Emission Reductions ............................................................................................ 18 

Upgrading Rim Seals .................................................................................................................................. 18

Upgrading Roof Fittings ............................................................................................................................ 18 

Domed Roofs ................................................................................................................................................ 19 

Internal Floating Roof Tanks, Vapor Control or Vapor Recovery Systems ..................................... 19 

Pressure Vacuum Vents ............................................................................................................................. 20 

Chapter 6 – Cost and Cost Effectiveness Analysis .................................................................... 22 

Cost Information ......................................................................................................................................... 22 

Cost Effectiveness Analysis ....................................................................................................................... 25 

Incremental Cost Effectiveness Analysis................................................................................................. 30 

Chapter 7 – Impact Assessment ................................................................................................ 32 

Environmental Impact Assessment .......................................................................................................... 32 
Table of Contents Final Staff Report

Proposed Rule 1178 December 11, 2001 ii

Socioeconomic Assessment ........................................................................................................................ 32 

Disruption of Production ........................................................................................................................... 32 

Refineries ...................................................................................................................................................... 32 

Non-refineries .............................................................................................................................................. 33 

Gasoline Cost Impact to Consumer ......................................................................................................... 34 

Comparative Analysis ................................................................................................................................ 34 

Chapter 8 – Comments and Responses ..................................................................................... 36 

Applicability................................................................................................................................................. 36 

Definitions .................................................................................................................................................... 40 

External Floating Roof Tanks ................................................................................................................... 44 

Domed External Floating Roof Tanks ..................................................................................................... 50 

Schedule of Installing Domed Roofs ........................................................................................................ 53 

Fixed Roof Tanks ........................................................................................................................................ 55 

Operator Inspection.................................................................................................................................... 58 

Test Methods and Procedures ................................................................................................................... 60 

Exemption .................................................................................................................................................... 64 

Emission Reductions and Cost Effectiveness Analysis ......................................................................... 65 

Appendix A - List of Affected Facilities 

Appendix B - Emission Reductions 

Appendix C - Cost Effectiveness Analysis 

Appendix D - Impact Study on Doming of External Floating Roof Tanks

Appendix E - Comparative Analysis 

Appendix F -Study on Storage Tanks and Atmospheric Pressure Relief Devices 
Executive Summary Final Staff Report

Proposed Rule 1178 EX-1 December 11, 2001

Executive Summary 

Proposed Rule 11781 - Further Reduction of VOC Emissions From Storage Tanks at Petroleum 

Refineries has been developed to implement Phase 1 of the 1999 Air Quality Management Plan 

(AQMP) Control Measure FUG-05 – Further Emission Reductions from Large Fugitive VOC 

Sources, and portions of the Control Measure FUG-03 – Further Emission Reductions from 

Floating Roof Tanks, and portions of the Control Measure FUG-04 – Further Emission 

Reductions from Fugitive Sources. 

The purpose of the Proposed Rule 1178 is to further reduce emissions of volatile organic 

compounds (VOCs) from storage tanks at petroleum facilities with annual VOC emissions of 

more than 40,000 lbs (20 tons). The provisions of the Proposed Rule 1178 apply to petroleum 

facilities operating storage tanks that have design capacity equal to or greater than 75,000 liters 

(19,815 gallons) and are used to store materials with a true vapor pressure of greater than 5 mm 

Hg (0.1 psi) absolute under actual storage conditions. 

The petroleum facilities subject to the Proposed Rule 1178 include facilities engaged in the 

production, refining, storage, transfer or distribution of crude petroleum or petroleum products as 

defined in the Standard Industrial Classification for crude petroleum and natural gas (SIC code 

1311), petroleum refining (SIC code 2911), petroleum bulk stations and terminals (SIC code 

5171), or other related industries (e.g., SIC codes 4226, 4612, 4613, 4923 and 5541). 

To further reduce evaporative emission losses and minimize leaks, the Proposed Rule 1178 

establishes the following requirements for external floating roof tanks, internal floating roof 

tanks, fixed roof tanks and pressure-vacuum vents. 

Proposed Requirements for External Floating Roof Tanks 

 For facilities exceeding 20 tons annual VOC emissions for emission inventory year 2000, 

Byby July 1, 20022003, retrofit each deck opening with covers that are gasketed and/or 

bolted, and with sleeves and wipers, and retrofit rim seal systems with the best available rim 

seal systems for external floating roof tanks containing materials with true vapor pressure 

<3psia. Facilities with annual VOC emissions exceeding 20 tons for any emission inventory 

year subsequent to 2000 will have one year to comply with these requirements after becoming 

subject to the rule.

 

1

Public Notice and Public Workshop for the Proposed Rule 1178 are the Public Notice and Public Worshop for the Proposed Rule 

1173.1. Upon request of the facilities subject to the Proposed Rule 1173.1, District Staff has changed the number of the proposed 

rule from 1173.1 to 1178 after the Public Workshop.
Executive Summary Final Staff Report

Proposed Rule 1178 EX-2 December 11, 2001

 By July 1, 2003, retrofit rim seal systems with the best available rim seal systems on external 

floating roof tanks containing materials with true vapor pressure <3psia. The best available 

rim seal system is a liquid mounted or mechanical shoe primary seal and a rim mounted 

secondary seal. 

 For facilities exceeding 20 tons annual VOC emissions for emission inventory year 2000, 

Byby January 1, 20068, retrofit all external floating roof tanks containing materials having 

true vapor pressure greater than or equal to 3 psia with domed roofs, upgrading rim seal 

systems and deck fittings. Facilities with annual VOC emissions exceeding 20 tons for any 

emission inventory year subsequent to 2000 will have six years to comply with these

requirements after becoming subject to the rule.

Proposed Requirements for Internal Floating Roof Tanks 

For facilities exceeding 20 tons annual VOC emissions for emission inventory year 2000, wWhen 

the tank is scheduled for emptying and degassing, but no later than January 1, 2007, retrofit each 

deck opening with covers that are gasketed and/or bolted, and with sleeves and wipers to further 

reduce evaporative losses. Facilities with annual VOC emissions exceeding 20 tons for any 

emission inventory year subsequent to 2000 will have five years to comply with these

requirements after becoming subject to the rule.

Proposed Requirements for Fixed Roof Tanks and Pressure-Vacuum Vents 

For facilities exceeding 20 tons annual VOC emissions for emission inventory year 2000, Nno 

later than January 1, 2007, convert the fixed roof tanks containing materials with true vapor 

pressure greater than or equal to 0.1 psia that are currently vented to the atmosphere to internal 

floating roof tanks or external floating roof tanks. Alternatively, the operator may choose to vent 

these tanks to a vapor control system or vapor recovery system having at least 95% control 

efficiency, or to fuel gas system. In addition, the operator shall maintain all pressure-vacuum 

vents to meet 500 ppm measured in accordance with EPA Method 21. Facilities with annual 

VOC emissions exceeding 20 tons for any emission inventory year subsequent to 2000 will have 

five years to comply with these requirements after becoming subject to the rule.

No later than January 1, 2007, maintain all pressure-vacuum vents to meet 500 ppm measured in 

accordance with EPA Method 21 and have a set point that is set to within 10% of the maximum 

allowable working pressure of the roof or at least 0.5 psig to further reduce evaporative losses.

To facilitate implementation uniformity, the provisions for record keeping, reporting, and selfinspecting of Proposed Rule 1178 are designed in a similar fashion to District Rule 463 and Title 

V.
Executive Summary Final Staff Report

Proposed Rule 1178 EX-3 December 11, 2001

Exemption

Several exemptions are allowed in the rule. Most important exemptions are 1) exempt crude oil 

tanks from doming requirements, 2) facilities with emission cap equal to or less than 20 tons per 

year shall be exempt from the rule requirements, and 3) tanks with true vapor pressure limits less 

than 3 psia shall be exempt from doming requirements.

 

Estimates of Emission Reductions 

The total emission reductions for this proposed rule are estimated to be 1.407 tons per day where: 

 0.021 ton per day is associated with upgrading the rim seal systems for external floating roof 

tanks, 

 0.18 ton per day is associated with upgrading deck fittings for external and internal floating 

roof tanks, 

 0.890.95 ton per day is associated with installing domed roofs on external floating roof tanks 

containing organic liquids with vapor pressures greater than or equal to 3 psia, excluding 

crude oil tanks,

 0.17 ton per day is associated with retrofitting fixed roof tanks containing organic liquids with 

vapor pressures greater than 1 psia that are currently vented to the atmosphere, 

 0.15 ton per day is associated with maintaining PV vents to achieve 500 ppm leak threshold. 

Cost Effectiveness Analysis 

Staff has performed a cost effectiveness analysis for this proposed rule to provide a cost 

effectiveness for each control measure, and an overall cost effectiveness for the entire proposed 

rule. The cost effectiveness for the entire proposed rule is $11,4739,583 2, 3per ton VOC reduced. 

As required under state law, staff has also determined an incremental cost effectiveness of an 

alternative control option that meets the reduction objective of the rule. For this alternative 

control scenario, described at the end of Chapter 6 of this report, the cost effectiveness is 

 

2

Specifically for doming, the cost effectiveness above represents the doming of 195 external floating roof tanks containing 

materials with TVP ≥ 3 psia at refineries and non-refineries, excluding crude oil tanks. For doming, the cost effectiveness includes

cost of domed roofs as installed, cost for obtaining permits, project management cost, loss-of-use cost, annual maintenance cost, 

annual insurance and property taxes, annual emission savings, product savings, and self-inspection savings. The cost effectiveness 

for tanks containing crude oils were about $62,000 per ton VOC reduced. 

3

 The risk of having fire on domed external floating roof tanks is low, much lower than on external floating roof tanks. However, 

for an extreme worst case scenario, where cost of a fire suppression system is included, the cost effectiveness factor would be 

$10,974 per ton VOC reduced in comparison to $9,583 per ton VOC reduced where the cost of a fire suppression system is not 

included.
Executive Summary Final Staff Report

Proposed Rule 1178 EX-4 December 11, 2001

$19,85521,536 per ton VOC reduced, and the incremental cost effectiveness is $113,375121,330

per ton VOC reduced. 
Chapter 1 – Background Final taff Report

Proposed Rule 1178 1 December 11, 2001 

Chapter 1 – Background 

Legislative Authority 

The California Legislature created the Air Quality Management District (District) 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 South Coast Air Basin (Basin). By statute, the District 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 

District must adopt rules and regulations that implement the AQMP (Health and Safety Code 

Section 40440(a)). 

Proposed Rule 1178 will implement the first phase of the 1999 Air Quality Management Plan 

(AQMP) Control Measure FUG-05 – Further Emission Reductions from Large Fugitive VOC 

Sources, and portions of the Control Measure FUG-03 – Further Emission Reductions from 

Floating Roof Tanks, and portions of the Control Measure FUG-04 – Further Emission 

Reductions from Fugitive Sources. A total of 2.9 tons/day of reductions are expected by the end 

of 2008 when all three phases of the Control Measure FUG-05 are implemented. These VOC 

emission reductions are needed to contribute towards achieving attainment of the national 

ambient air quality standard for ozone Section 182(b)(1)(A) of the federal CAA. 

The AQMP Control Measures and District Rules applicable to fugitive VOC emissions are 

briefly described below. 

AQMP Control Measures 

FUG-03 - Further Emission Reductions from Floating Roof Tanks 

Presently, Rule 463 places exemptions on both tank capacity and vapor pressure of the organic 

solvent stored. This control measure directs District staff to quantify emissions associated with 

the storage tanks that are currently exempt from Rule 463, and if the emissions are significant, 

District staff will proceed with identifying the appropriate control options and addressing the 

cost effectiveness. 

FUG-04 - Further Control of Emissions from Fugitive Sources 

This control measure is designed to control fugitive VOC emissions from petroleum and 

chemical-related industries, including refineries, oil and gas production fields, natural gas 

processing plants and pipeline transfer stations. 

FUG-05 - Further Emission Reductions from Large Fugitive VOC Sources 

This control measure focuses on reducing emissions from the top 100 fugitive VOC-emitting 

facilities. The top VOC-emitting facilities targeted in this control measure consist mainly of 

refineries. It should be noted that control measure FUG-05 also includes control of VOC 

fugitive emissions from chemical plants and manufacturing facilities. The major coating and 

solvent operations are addressed separately under control measure CTS-08. 
Chapter 1 – Background Final taff Report

Proposed Rule 1178 2 December 11, 2001 

District Rules 

There are currently two District rules regulating fugitive VOC emissions: 

Rule 463 

Organic Liquid Storage was adopted in 1977 and recently amended in 1994. It applies to any 

aboveground stationary tank with a capacity of 75,000 liters (19,815 gallons) or greater used for 

storage of organic liquids and any aboveground tank with a capacity between 950 liters (251 

gallons) and 75,000 liters (19,815 gallons) used for storage of gasoline. 

Rule 1173 

Fugitive Emissions of Volatile Organic Compounds, was adopted in 1989 and was recently 

amended in 1994. Its purpose is to control VOC leaks from valves, fittings, pumps, compressors, 

pressure relief devices, diaphragms, hatches, sight glasses and meters at refineries, chemical 

plants, oil and gas production fields, natural gas processing plants and pipeline transfer stations. 

Rule 1173 does not address refinery storage tanks, or the pressure relief/vacuum vents associated 

with them. 

Development Process of Proposed Rule 1178 

In 1999, the District settled a litigation initiated by three environmental organizations, the 

Natural Resources Defense Council (NRDC), the Coalition for Clean Air and Communities for a 

Better Environment (CBE) for failing to implement the 1994 AQMP. The settlement agreement, 

which was incorporated in the 1999 AQMP amendments, commits the District to develop and 

implement several stationary source control measures and achieve a specific level of emission 

reductions within a specific time frame. Several of these control measures are designed to 

further reduce fugitive emissions from refineries. 

In an effort to support implementation of the control measures applicable to refineries and/or 

identify new control options not identified in the AQMP control measures or existing rules, the 

settlement agreement also committed the District to further study fugitive emissions from tanks 

and pressure relief devices (PRDs) operated by refineries. More specifically, the commitment 

directed the District to further refine current emission inventories applicable to tanks and PRDs, 

including atmospheric PRDs and release events. The District was also required to identify and 

evaluate potential control options, including those identified by the Bay Area AQMD during the 

development of amendments to Regulation 8 - Organic Compounds; Rule 5 - Storage of Organic 

Liquids; and proceed with amendments to existing rules and/or the development of new rules in 

the event the studies identify meaningful emission reduction potentials and technologically 

feasible and cost-effective controls. 

To fulfill its commitment to further study fugitive emissions from storage tanks and PRDs 

operated by refineries, District staff worked closely with refineries and environmental 

organizations and developed two survey questionnaires. The first survey focused on obtaining 

information on storage tanks and the second survey focused on PRDs. Based on information 

submitted to the District following the first survey, it has been concluded that meaningful 
Chapter 1 – Background Final taff Report

Proposed Rule 1178 3 December 11, 2001 

emission reductions do exist and that the control strategies applicable to these sources are 

technically feasible and cost effective. Therefore, the District has decided to proceed with a 

rulemaking process as outlined in the settlement agreement. 

Affected Industries 

Control Measure FUG-05 focuses on reducing VOC emissions from the higher emitting 

petroleum facilities, other than coating and solvent operations. District Control Measure FUG05 calls for a reduction of 3 tpd VOC under three phases. The Proposed Rule 1178 will 

implement the first phase of the Control Measure FUG-05 by focusing in further reducing 

emissions from storage tanks at petroleum facilities with annual VOC emissions of more than 

40,000 lbs (20 tons). The Proposed Rule 1178 will partially implement portions of the Control 

Measure FUG-03 and FUG-04 which have no emission reduction commitments. 

Table 1-1 summarizes the annual emissions reported for the 1996-1997 emission inventory year 

for the top 91 highest emitting facilities in the District. Table 1-1 shows the emissions in four 

emission groups and details the contribution of fugitive, tank, process and combustion emissions 

to total emissions for petroleum facilities as well as non-petroleum facilities. As shown in Table 

1-1, the emissions from storage tanks at petroleum facilities contribute about 90% of the total 

emissions from storage tanks. Petroleum facilities in Table 1-1 include petroleum refineries (SIC 

2911), facilities primarily engaged in the production, refining, storage, transfer or distribution of 

crude petroleum or petroleum products (SIC 1311), petroleum bulk stations and terminals (SIC 

5171), and related industries. 

While Table 1-1 relies on information submitted to the District as part of the 1996-1997 Annual 

Emissions Reporting process, in assessing the emission inventory and potential reductions from 

tank operated by the petroleum refineries subject to the Proposed Rule 1178, staff has relied on 

the information submitted as part of the recently conducted tank study attached in Appendix F of 

this draft staff report. 
Chapter 1 – Background Final taff Report

Proposed Rule 1178 4 December 11, 2001 

Table 1-1 - Emissions Summary based on 1996-97 Annual Emission Reports, excluding 

Forms B3/B3U 

Group 

Cut 

Point 

(tpy) 

No. of Facilities Fugitive 

(tpy) 

 Tank 

(tpy) 

Process 

(tpy) 

Combustion 

(tpy) 

Total Emissions 

(tpy) 

Petroleum 

Others 

Petroleum 

Others 

Petroleum 

Others 

Petroleum 

Others 

Petroleum 

Others 

Petroleum 

Others 

I >150 10 2 2,584.43 0 820.98 0 463.66 956.88 1,184.44 2.87 5,053.50 959.75 

II >100 - 

150 

1 6 47.21 14.96 6.25 2.04 0.56 571.02 75.17 92.67 129.19 680.69 

III >50 - 

100 

7 8 420.26 3.15 34.5 86.35 0.01 343.14 37.02 136.31 491.8 568.96 

IV >20 - 

50 

19 38 286.24 74.59 196.54 63.48 22.25 520.41 36.54 544.77 541.58 1,203.26 

Total 37 54 3,338.14 92.7 1,058.28 151.87 486.48 2,391.46 1,333.17 776.62 6,216.06 3,412.65 
Chapter 2 – Emissions Inventory Final Staff Report

Proposed Rule 1178 5 December 11, 2001 

Chapter 2 – Emissions Inventory 

The inventory of storage tanks and storage tank emissions for eight major petroleum refineries 

(SIC 2911) is summarized in Table 2-1 and Table 2-3, respectively. This information is taken 

from a tank study attached in Appendix F of this staff report. For 320 petroleum facilities other 

than petroleum refineries, staff has relied on the information submitted as part of the 1999-2000 

Annual Emissions Reporting process. The inventory of storage tanks and storage tank emissions 

for the 320 petroleum facilities (SIC 1311, 5171 and others) are summarized in Table 2-2 and 2-

4, respectively. 

Table 2-1 – Overall Tank Inventory from Petroleum Refineries 

Refinery

Fixed Roof External 

Floating Roof 

Internal 

Floating Roof

Domed External 

Floating Roof Total 

1 55 50 4 0 109 

2 68 111 13 0 192 

3 92 13 1 1 107

4 45 66 1 2 114

5 3 29 2 0 34

6 4 87 0 4 95

7 10 27 0 0 37

8 31 0 14 0 45

Total 308 383 35 7 733

Note: The storage tank inventory at other three small petroleum refineries is estimated to be about 22 fixed 

roof tanks, 27 external floating roof tanks, and 3 internal floating roof tanks. Total storage tank inventory for 

petroleum refineries is therefore approximately 785 tanks. 

Table 2-2 – Overall Tank Inventory from Non-Refinery Petroleum 

Facilities 

Facility

Fixed Roof External 

Floating Roof 

Internal 

Floating Roof

Domed External 

Floating Roof Total 

1 0 5 10 0 15

2 2 11 23 0 36

3 0 21 0 0 21

4 2 8 0 0 10

5 2 10 0 0 12

6 8 11 31 0 50

7 7 4 6 0 17 

8 0 2 18 0 20 

9 2 8 0 0 10

10 76 6 27 0 109
Chapter 2 – Emissions Inventory Final Staff Report

Proposed Rule 1178 6 December 11, 2001 

Table 2-2 – Overall Tank Inventory from Non-Refinery Petroleum 

Facilities (Continued) 

Facility Fixed Roof 

External 

Floating Roof 

Internal 

Floating Roof

Domed External 

Floating Roof Total 

11 0 24 6 0 30

12 14 14 1 7 36

13 15 0 0 0 15

14 5 0 0 0 5

15 3 0 0 0 3

16 10 0 0 0 10

17 2 8 5 0 15

18 0 5 7 0 12

19 0 2 1 0 3

20 3 0 0 0 3

21 5 0 0 0 5

22 0 2 7 0 9

23 2 0 0 0 2

24 25 0 0 0 25

25 4 0 0 0 4

26 12 0 0 0 12

27 11 0 0 0 11

28 21 0 0 0 21

29 21 0 0 0 21

30 5 0 0 0 5

31 1 2 1 0 4

32 75 0 20 0 95

33 2 0 0 0 2

34 1 0 0 0 1

Total 33308 14339 1631 7 64615
Chapter 2 – Emissions Inventory Final Staff Report

Proposed Rule 1178 7 December 11, 2001 

Table 2-3 – Overall Emission Inventory for Tanks at Petroleum Refineries 

Refinery

Fixed 

Roof 

(tpy) 

External 

Floating 

Roof 

(tpy) 

Internal 

Floating 

Roof 

(tpy) 

Domed 

External 

Floating 

Roof 

(tpy) 

Total 

(tpy) 

1 50.97 56.50 9.96 0 117.44

2 28.47 174.19 2.70 0 205.36

3 27.45 64.87 0.73 1.05 94.10

4 12.39 85.21 1.72 1.22 100.54

5 0.58 24.45 0.31 0 25.34

6 0.10 26.24 0 1.08 27.42

7 0.43 19.73 0 0 20.16

8 0.30 0 5.30 0 5.6

Total 120.69 451.19 20.72 3.35 595.95(Note)

Note: The storage tank emission inventory at other three small petroleum refineries is estimated to be 

about 18.46 tpy from their 99-00 inventory. Total storage tank emission inventory for the petroleum 

refineries is therefore approximately 614.41tpy. 

Table 2-4 – Overall Emission Inventory for Tanks at Non-Refinery 

Petroleum Facilities 

Facility 

Fixed 

Roof 

(tpy) 

External 

Floating 

Roof 

(tpy) 

Internal 

Floating 

Roof 

(tpy) 

Domed 

External 

Floating 

Roof 

(tpy) 

Total 

(tpy) 

1 0.00 10.43 40.01 0 50.43

2 5.31 5.83 43.56 0 54.71

3 0.00 45.52 0.00 0 45.52

4 2.92 31.38 0.00 0 34.30

5 0.24 20.93 0.00 0 21.17

6 0.35 43.74 19.84 0 63.92

7 8.92 8.53 6.01 0 23.47

8 0.00 0.56 21.75 0 22.31

9 0.43 23.29 0.00 0 23.72

10 18.91 28.11 106.61 0 153.62
Chapter 2 – Emissions Inventory Final Staff Report

Proposed Rule 1178 8 December 11, 2001 

Table 2-4 – Overall Emission Inventory for Tanks at Non-Refinery 

Petroleum Facilities (continued) 

Refinery Fixed 

Roof 

(tpy)

External 

Floating 

Roof 

(tpy)

Internal 

Floating 

Roof 

(tpy)

Domed 

External 

Floating 

Roof 

(tpy)

Total

(tpy)

11 0.00 13.20 1.29 0.00 14.50

12 3.03 6.18 0.07 0.00 9.28

13 0.88 0.00 0.00 0.00 0.88

14 0.62 0.00 0.00 0.00 0.62

15 2.39 0.00 0.00 0.00 2.39

16 13.40 0.00 0.00 0.00 13.40

17 2.41 3.79 12.94 0.00 19.14

18 0.00 0.20 2.89 0.00 3.09

19 0.00 5.28 2.05 0.00 7.33

20 0.33 0.00 0.00 0.00 0.33

21 1.45 0.00 0.00 0.00 1.45

22 0.00 5.86 7.32 0.00 13.18

23 0.30 0.00 0.00 0.00 0.30

24 7.13 0.00 0.00 0.00 7.13

25 0.41 0.00 0.00 0.00 0.41

26 2.91 0.00 0.00 0.00 2.91

27 0.92 0.00 0.00 0.00 0.92

28 5.44 0.00 0.00 0.00 5.44

29 1.02 0.00 0.00 0.00 1.02

30 0.55 0.00 0.00 0.00 0.55

31 0.46 5.68 3.18 0.00 9.32

32 5.64 0.00 4.75 0.00 10.39

33 3.59 0.00 0.00 0.00 3.59

34 0.033 0.00 0.00 0.00 0.033

Total 865.3774 25847.515 27267.2704 0.00 61700.1533

As shown in Table 2-5, the total inventory of storage tanks subject to the Proposed Rule 1178 is 

about 1,43100 storage tanks with a total annual emission of 1,23215 tons per year (3.372 tons 

per day). 
Chapter 2 – Emissions Inventory Final Staff Report

Proposed Rule 1178 9 December 11, 2001 

Table 2-5 – Summary of Tank Inventory and Emissions from Tanks 

 

 Fixed Roof External 

Floating 

Roof 

Internal 

Floating 

Roof 

Domed 

External 

Floating Roof 

Total 

No of Tank 6638 55349 201199 14 1,43100

Emissions 207.06 

206.43tpy 

72817.162

tpy 

29287.9976

tpy 

3.35 tpy 1,23114.567

4 tpy 
Chapter 3 – Control Technology Final Staff Report

Proposed Rule 1178 10 December 11, 2001 

Chapter 3 – Control Technology 

Rim Seal Systems 

Floating roof tanks are equipped with a rim seal system to minimize evaporation losses around 

the rim. Chapters 4 and 5 of the tank study attached to Appendix F of this report provide: 

• A description of a rim seal system for floating roof tanks; 

• An inventory of the existing rim seal systems for storage tanks in the District; and 

• A comparison in rim seal losses between different types of rim seal systems. 

The tank study in Appendix F of this report shows that the most effective rim seal system in 

controlling evaporative losses around the tank rim of a welded tank consists of a mechanical 

shoe or liquid-mounted primary seal and rim-mounted secondary seal. For a riveted tank, the 

most effective control system is a mechanical shoe vapor mounted primary seal and a rimmounted secondary seal. As shown in Table 4-5 of this study, a best rim seal system can reduce 

evaporative losses by 51% to 85%. 

Deck Fittings 

The external and internal floating roof tanks are equipped with fittings that penetrate the decks 

and serve operational functions. Deck fittings can be a source of evaporative losses when they 

require openings in the deck. Chapters 4 and 5 of the tank study in Appendix F of this report 

provide: 

• A description of the deck fittings of floating roof tanks; 

• An inventory of the existing deck fittings for the storage tanks in the District; and 

• A comparison in deck fitting losses between different types of deck fittings. 

The tank study in Appendix F of this report shows that the most effective control option for deck 

fittings is to: 

• Provide each access hatch and each gauge float well with a cover that is gasketed and bolted 

which is closed at all times except when the hatch or well must be opened for access; 

• Equip each gauge hatch/sample well and each ladder well with a gasketed cover which is 

closed at all times except when the hatch or well must be open for access; 

• Gasket each rim vent and each vacuum breaker; 

• Provide each roof drain that empties into the stored liquid and each sample pipe or well with 

a slotted membrane fabric cover that covers at least 90 percent of the area of the opening; 

• Equip each unslotted guide pole well with a sliding cover that is gasketed and have a flexible 

fabric sleeve seal or wiper; and 
Chapter 3 – Control Technology Final Staff Report

Proposed Rule 1178 11 December 11, 2001 

• Equip each slotted guide pole well with a gasketed sliding cover, a flexible fabric sleeve seal 

and wiper, and/or a gasketed float. 

The inventory of deck fittings in Appendix F shows that about: 

• 50% of the deck fittings for storage tanks in the District operated by refineries are currently 

equipped with gasketed covers; 

• 50% of unslotted guidepoles for storage tanks in the District operated by refineries are 

equipped with sliding gasketed covers, sleeves and wipers; and 

• 50% of slotted guidepoles for storage tanks in the District operated by refineries are equipped 

with sliding gasketed covers, sleeve seals, wipers, and gasketed floats. 

As shown in Table 4-8 of the tank study in Appendix F, in general, providing gasketed and/or 

bolted covers can reduce evaporative losses through the deck fittings from 3% to 98%. 

Domed External Floating Roof Tanks 

A domed roof is a fully triangulated structure typically made of aluminum that is self-supporting 

from its periphery. A domed roof can further reduce evaporative losses from external floating 

roof tanks by: 

• Acting as a wind barrier and eliminating evaporative losses caused by wind effects; and 

• Eliminating evaporative losses caused by supporting columns. Standard internal floating 

roof tanks need support columns for their fixed coned roof. Geodesic domes are selfsupported structures thus greatly reducing the number of openings for support columns, and 

the evaporative losses associated with these openings. 

There are many other benefits to cover a petroleum storage tank with an aluminum geodesic 

dome. Some of the benefits are: 

• Keeping rain from entering into the tank and possibly contaminating the product; 

• Preventing corrosion of the steel roof by eliminating standing water; 

• Eliminating the need for disposal of contaminated water from the roof; and 

• Protecting the existing rim seals from environmental hazards. 

The aluminum domed roof is almost a maintenance-free structure, can be built on the ground and 

lifted into place, and can be installed without taking the tank out-of-service. Chapter 6 of the 

tank study in Appendix F provides a comparison in rim losses and deck fitting losses of external 

floating roof tanks and domed external floating roof tanks. As shown in Table 6-3 of this study, 

retrofitting external floating roof tanks with domed roofs can reduce the rim-seal losses by 80%, 

and the deck-fitting losses by 50%. 
Chapter 3 – Control Technology Final Staff Report

Proposed Rule 1178 12 December 11, 2001 

Internal Floating Roof Tanks 

Converting an existing fixed roof tank currently vented to the atmosphere to an internal floating 

roof tank can further reduces evaporative losses. Table 5-5 and 5-6 of the tank study in 

Appendix F provides a comparison in rim seal losses, deck fitting losses, withdrawal losses, and 

total losses of fixed roof tanks and internal floating roof tanks. As shown in Table 5-6 of this 

study, converting fixed roof tanks to internal floating roof tanks can reduce working losses by 

95%, breathing losses by 90%, and total losses by 94%. 

Vapor Recovery or Vapor Control Systems 

Venting fixed roof tanks to a vapor recovery system or a vapor control system is a control option 

for fixed roof tanks. Several types of vapor recovery system can be used, including vapor/liquid 

absorption, vapor compression, vapor cooling, vapor/solid adsorption, or a combination of these. 

Thermal oxidation such as venting to process heaters or flaring is another method to control 

emissions from fixed roof tanks. The overall control efficiencies of vapor control or vapor 

recovery systems are reported to be as high as 90% to 99%. (Reference: Control Techniques for 

Volatile Organic Compound Emissions from Stationary Sources. EPA, 1994.). 

Pressure Vacuum Vents 

Low leakage pressure vacuum vents at 500 ppm measured in accordance with EPA Method 21 

are currently available in the market. One example is the Protectoseal’s PIN-TECH pressure 

vacuum vents which have a unique buckling pin technology to hold the vents closed and 

minimize leakage up to the relief set point. The performance of the PIN-TECH pressure vacuum 

vents have been verified under the U.S. EPA Environmental Technology Verification Program. 

(Manufacturer’s Catalog and Web Site of Protectoseal, 2000). A good maintenance program can 

also help to keep pressure vacuum vents at a leakage rate of 500 ppm. 
Chapter 4 – Proposed Rule 1173.1 Final Staff Report

Proposed Rule 1178 13 December 11, 2001 

Chapter 4 – Proposed Rule 1178 

Highlights of the Proposed Rule 1178 are: 

Applicability 

The purpose of the Proposed Rule 1178 is to further reduce emissions of volatile organic 

compounds (VOCs) from storage tanks at petroleum facilities. The rule applies to all storage 

tanks that have design 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 beginning in year 19992000.

Definitions 

• Terminology such as “storage tanks” and “petroleum facilities” that is used in the 

applicability section of the Proposed Rule 1178 is defined for clarity. 

• Terminology such as “mechanical shoe primary seal”, “resilient-filled primary seal”, 

“secondary seal”, “liquid-mounted seal”, “vapor-mounted seal”, “access hatch”, “slottted and 

unslotted guidepole”, “pole float”, “pole sleeve”, “pole wiper”, “rim seal”, “vacuum breaker” 

that is used in the requirements section of the Proposed Rule 1178 is defined for clarity. 

• Terminology such as “exempt compounds” that has been defined in Rule 102 is referred to 

by citing reference to Rule 102. 

Requirements 

Facilities with Annual Emissions > 20 tons for Emission Inventory Year 2000

External Floating Roof Tanks Containing Materials With TVP <3psia

The following three requirements are proposed for external floating roof tanks: 

• By July 1, 2002July 1, 2003, each deck fitting/well will be equipped with cover that is 

gasketed/bolted, or with sleeve and wiper to reduce evaporative losses. Specifically: 

 Each access hatch and gauge float well will be equipped with a cover that is gasketed and 

bolted. The cover shall be closed at all times, with no visible gaps, except when the hatch 

or well must be opened for access. 

 Each gauge hatch/sample well will be equipped with a cover that is gasketed. The cover 

shall be closed at all times, with no visible gaps, except when the hatch or well must be 

opened for access. 

 Each rim vent, vacuum breaker and roof leg will be gasketed. 
Chapter 4 – Proposed Rule 1173.1 Final Staff Report

Proposed Rule 1178 14 December 11, 2001 

 Rim vents will be closed at all times when the roof is floating; and will be set to open 

only when the roof is being floated off the roof leg supports or when the pressure beneath 

the rim seal exceeds the manufacturer's recommended setting. 

 Vacuum breakers will be closed at all times when the roof is floating; and will be set to 

open only when the roof is being floated off or is being landed on the roof leg supports. 

 Each open floating roof drain will be equipped with a slotted membrane fabric cover that 

covers at least 90 percent of the area of the opening. 

 Each unslotted guidepole well will be equipped with a gasketed sliding cover and a 

flexible fabric sleeve or wiper. In addition, each unslotted guidepole will be equipped 

with a gasketed cover at the end of the pole. The cover will be closed at all times except 

when gauging or sampling. 

 Each slotted guidepole will be equipped with a gasketed cover, a pole wiper and a pole 

sleeve. The pole sleeve will be extended into the stored liquid. Each slotted guidepole 

with a pole float will be equipped with a gasketed cover, a pole wiper, and a pole float 

wiper. The wiper or seal of the pole float will be at or above the height of the pole wiper. 

The gasketed cover of each slotted guidepole will be in place over the guidepole opening 

at all times except when the cover must be opened for access. The pole float will be 

floating within the guidepole at all times except when it must be removed for access to 

the stored liquid or when the tank is empty. 

• By July 1, 2003, external floating roof tanks will be equipped with a rim seal system that 

consists of two seals. The primary seal will be mechanical shoe or liquid mounted for 

welded tanks and mechanical shoe for riveted tanks. The secondary seal will be rim 

mounted. The rim seal system will cover the annular space between the external floating 

roof and the wall of the storage tank in a continuous fashion. 

External Floating Roof Tanks Containing Materials With TVP ≥3psia

By January 1, 20062008, external floating roof tanks containing materials having true vapor 

pressure greater than or equal to 3 psia will be equipped with domed roofs, upgraded rim seals 

and deck fittings to reduce evaporative losses. 

Internal Floating Roof Tanks 

At the next time the tank is scheduled for emptying and degassing but no later than January 1, 

2007, each deck fitting/well of an internal floating roof tank will be equipped with cover that is 

gasketed/bolted, or with sleeve and wiper to reduce evaporative losses. Specifically: 

• Each fixed roof support column and well will be equipped with a sliding cover that is 

gasketed or flexible fabric sleeves. 

• Each ladder well will be equipped with a cover that is gasketed. The cover will be closed at 

all times, with no visible gaps, except when the well must be opened for access. 
Chapter 4 – Proposed Rule 1173.1 Final Staff Report

Proposed Rule 1178 15 December 11, 2001 

• Other deck fittings will meet the same specifications as external floating roof tanks. 

Fixed Roof Tanks 

• Currently nineteen fixed roof tanks in the District operated by the refineries and fifty-one 

operated by the non refineries containing materials with true vapor pressure greater than or 

equal to 0.1 psia are vented directly to the atmosphere. By January 1, 2007, the 70 fixed roof 

tanks must be equipped with a closed vent system, and the vapors displaced from these tanks 

must be vented to a vapor control system or a vapor recovery system. The vapor recovery or 

vapor control system shall haveing at least an overall recovery efficiency or control 

efficiency of 95%; or a fuel gas system. The operator is allowed to comply with this 

requirement by converting their fixed roof tanks to internal floating roof tanks or external 

floating roof tanks. 

• By January 1, 2007, the pressure-vacuum vents of all tanks subject to this Proposed Rule 

1178 are required to: 

 Have a set point set to within 10% of the maximum allowable working pressure of the 

roof or at least 0.5 psig to reduce breathing losses. 

 Be maintained in a vapor tight condition, that is less than 500 ppm measured by EPA 

Method 21, at all times except when the operating pressure of the fixed roof tank exceeds 

the manufacturer’s recommended setting. 

Facilities with Annual Emissions > 20 tons for Any Emission Inventory Year Subsequent to 

2000:

These facilities will have one year to comply with the requirements for external floating roof 

tanks containing materials with TVP < 3psia; six years to comply with the doming requirements 

for external floating roof tanks containing materials with TVP ≥ 3psia; and five years to comply 

with the requirements for fixed roof tanks and internal floating roof tanks after becoming subject 

to the rule, respectively.

Other Requirements 

Test Methods and Procedures

• Test Method for determining 0.1 psia true vapor pressure of organic liquids.

The test method for determining the 0.1 psi true vapor pressure for rule applicability does not 

directly measure vapor pressure, but uses surrogate test methods. The surrogate test methods 

are to be used in determining applicability and not an actual measurement for vapor pressure. 

The surrogates consist of flash point for ambient temperature tanks and distillation 

temperature at 10% recovery for heated tanks. The reason for this is to address a long 

standing difficulty in measuring low vapor pressures in that there are no accurate and 

reasonably cost effective methods known. This problem has been compounded over time as 

vapor pressure thresholds and limits decrease with increased rule stringency. For tanks 

Formatted: Bullets and Numbering
Chapter 4 – Proposed Rule 1173.1 Final Staff Report

Proposed Rule 1178 16 December 11, 2001 

storing organic liquids at ambient temperature, the flash point method was chosen as a low 

cost, well established method that is quite capaple in discerning between petroleum products. 

The 100 oF flash point was chosen as to mimic the exemption of the products that were 

excluded from the inventory and cost effectiveness analyses. Most tanks containing diesel 

and kerosene were excluded from these analyses. ASTM Method D86 is to be used for 

heated tank contents due to its flexibility in being able to adjust its applicability limit to the 

tank contents storage temperature. Actual storage temperature is measured at the time of 

sampling. This temperature can be taken from near the top of the tank even if stratified 

liquid temperatures exist as to represent the liquids that would most influence the emissions. 

The reason for the different test method for heated tank contents is that both vapor pressure 

and emissions increase with storage temperature, particularly at the upper liquid layer 

interface.

• Test Method for determining 3 psia true vapor pressure of organic liquids.

For measuring true vapor pressure for applicability of the 3 psia requirements, the referenced 

nomographs are currently located in Chapter 7 of EPA AP-42. For organic liquids stored at 

above ambient temperatures, actual storage temperature is measured at the time of sampling. 

This temperature can also be taken from near the top of the tank even if stratified liquid 

temperatures exist as to represent the liquids that would most influence the emissions. If, for 

example, as with sludge samples, the viscosity of the sample is sufficiently high so that it 

cannot be poured into the Method D323 vapor pressure apparatus, then it may be assumed 

that the vapor pressure is less than 3 psia. 

In addition, the District Laboratory Approval Program requirements will generally apply to 

the source test methods only and when testing for the control device efficiency requirements. 

Monitoring Requirements 

• External Floating Roof Tanks

 The rim seal system will be inspected by a certified person on a semiannual basis, and 

each time the tank is emptied and degassed, following the same procedures as specified 

in District Rule 463. 

 The deck fittings will be inspected by a certified person on a semiannual basis, and each 

time the tank is emptied and degassed, following the same procedures as specified in 

District Rule 463. 

• Domed External Floating Roof Tank and Internal Floating Roof Tanks 

 Visually inspect the rim seal system and roof openings using LEL on a semiannual basis. 

 Perform gap measurement of rim seal at least once every ten years and when the tank is 

emptied or degassed but no less than once every ten years.

 Perform EPA Method 21 and gap measurements of deck fittings at least once every ten 

years and when the tank is emptied or degassed but no less than once every ten years. 

Formatted: Bullets and Numbering
Chapter 4 – Proposed Rule 1173.1 Final Staff Report

Proposed Rule 1178 17 December 11, 2001 

• Fixed Roof Tanks 

 Conduct annual source testing and weekly monitoring operating parameters to ensure 

95% control efficiency. 

 Vapor tight conditions shall be determined using Method 21 on a quarterly basis. 

 Engineering data sheet is used to determine compliance with pressure-vacuum valve set 

point. 

Maintenance Requirements 

Any tank that does not comply with any provision of this rule, except the provisions related to 

pressure vacuum vents, will be brought into compliance within 72 hours of the determination of 

non-compliance. This is a current requirement in District Rule 463. 

Record Keeping and Reporting Requirements 

The operator will follow the record keeping and reporting requirements in District Rule 463, 

except that all records of operator inspection and repair will be kept at the facility for a period of

5 years and be made available to the Executive Officer upon request. 

Additional Tank Requirements 

The tanks in this rule are also required to comply with the requirements in Rule 463 such as gap 

requirements, PV vents setting, deck fittings requirements, or concentration of organic vapor 

space above internal floating roofs. 

Annual Status Report 

On or before each compliance date, the operator who is required to install a domed roof on 

external floating roof tanks must submit an annual status report to the District. The plan will 

include information such as a list of storage tanks subject to the requirement, a general 

description of each tank, a description of the compliance method chosen for each tank, and an 

estimated compliance date for each tank. 
Chapter 5 – Emissions Reduction Final Staff Report

Proposed Rule 1178 18 December 11, 2001 

Chapter 5 – Emission Reductions 

Chapters 3 through 7 of the tank study in Appendix F of this draft staff report contain 

information on control efficiencies of the control options recommended for this Proposed Rule 

1178. The emission reduction estimates for each control option are described below and are 

summarized in Table 5-1. 

Upgrading Rim Seals 

Table 4-5 of the tank study in Appendix F of this report provides information on percent 

reduction associated with each existing rim seal system installed on external floating roof tanks. 

For example, replacing a rim seal system equipped with only mechanical shoe primary seal with 

a rim seal system equipped with mechanical shoe primary seal and rim-mounted secondary seal 

will provide about 85% reduction in rim seal losses. 

Table B-1 of Appendix B of this report contains the total rim seal losses associated with each 

type of rim seal system. The emission reductions in Table B-1 are estimated based on the 

following equation: 

ER rimseal = Σi(E rimseal, i x PR rimseal, i ) (Equation 5-1) 

Where: 

ER rimseal = Total estimated emission reductions associated with upgrading rim seals 

E rimseal, i = Reported emissions associated with rim seal type i 

PR rimseal, i = Percent reduction associated with rim seal type i 

As shown in Appendix B and summarized in Table 5-1, the total emission reductions that would 

be achieved by replacing existing rim seal systems with the best rim seal systems is estimated 

about 2.55 tons per year for petroleum refineries. For facilities that are not petroleum refineries, 

the estimated reduction is about 1.46 tons per year. 

Upgrading Roof Fittings 

Table 4-8 of the tank study in Appendix F of this report provides a percent reduction associated 

with each existing deck fitting installed on external floating roof tanks. As an example, 

installing pole wiper and sleeve for a slotted guidepole/sample well will reduce deck-fitting 

losses by 93%. 

Table B-4 of Appendix B of this report contains the deck fitting losses from external and internal 

floating roof tanks located at the eight local petroleum refineries. The emission reductions 

associated with deck fittings are estimated as follows: 

ER deckfitting = Σi (E deckfitting, i x APR deckfitting, i ) (Equation 5-2) 
Chapter 5 – Emissions Reduction Final Staff Report

Proposed Rule 1178 19 December 11, 2001 

Where: 

ER deckfitting = Total emission reductions associated with upgrading deck fittings 

E deckfitting, i = Total reported emissions for storage tank type i 

 (i = 1 for external floating roof tanks and i = 2 for 

 internal floating roof tanks) 

APR deckfitting, i = Average percent reduction for storage tank type i 

 = Σj(N deckfitting, j x PR deckfitting, j ) / N (Equation 5-3) 

Where: 

N deckfitting, j = Number of deck fittings type j 

PR deckfitting, j = Percent reduction associated with deck fittings type j 

N = Total number of deck fittings for storage tank type i 

As shown in Tables B-2 and B-3, the average percent reductions for external floating roof tanks 

and internal floating roof tanks are 7.49% and 18.93% respectively. As shown in Appendix B 

and summarized in Table 5-1, the total emission reductions that would be achieved by upgrading 

existing deck fittings are estimated to be approximately 18.95 tons per year for petroleum 

refineries. For facilities that are not petroleum refineries, the estimated reduction is about 46.80 

tons per year. 

Domed Roofs 

Table 6-3 of the tank study in Appendix F shows that using a domed roof can achieve an average 

reduction of 79% for rim-seal losses, and 47% for deck fitting losses. As shown in Section B-3 

of Appendix BTable B-5 and summarized in Table 5-1, installing domed roofs on external 

floating roof tanks containing materials with true vapor pressures of 3 psia or greater, excluding 

crude oil tanks, will result in an emission reduction of 222.48189.47 tons per year for 11 

refineries, and 151.10134.74 tons per year for non-petroleum refineries.4 

Internal Floating Roof Tanks, Vapor Control or Vapor Recovery Systems 

Converting an existing fixed roof tank to an internal floating roof tank or venting the vapors to a 

vapor control/vapor recovery system will further reduce evaporative losses from the fixed roof 

 

4

Doming 28 crude oil tanks at refineries and 18 crude oil tanks at non-refineries would result in an emission reduction of 17.94 

tpy and 6.12 tpy, respectively. As shown in the cost effectiveness section in Chapter 6, the cost effectiveness factor of doming 

crude oil tanks would be approximately $62,000 per ton VOC reduced. Because of the high cost effectiveness factor, crude oil 

tanks shall be exempt from the doming requirements of the PR1178. 
Chapter 5 – Emissions Reduction Final Staff Report

Proposed Rule 1178 20 December 11, 2001 

tanks that are currently vented to the atmosphere. Table 3-3 of the tank study in Appendix F 

shows that 133 fixed roof tanks are currently vented to the atmosphere. The emissions 

associated with these fixed roof tanks are 86.94 tons per year. Out of the 133 fixed roof tanks 

vented to the atmosphere, there are 19 tanks containing materials having true vapor pressure 

greater than 0.1 psia from Refinery #1, 2, and 3. The emissions from these 19 tanks are 38.47 

tons per year. Venting these tanks to a vapor control system or a vapor recovery system, or 

converting these tanks to internal floating roof tanks or external floating roof tanks with primary 

and secondary seals will reduce the emissions from these tanks by at least 95%. The emission 

reductions that would be achieved are about 36.55 tons per year for petroleum refineries. For 

facilities that are not petroleum refineries, there are 51 tanks currently vented to the atmosphere 

containing materials having true vapor pressure greater than 0.1 psia. The estimated reduction is 

about 26.16 tons per year as shown in Table 5-1. 

Pressure Vacuum Vents 

Low leakage pressure vacuum vents at 500 ppm or less measured in accordance with EPA 

Method 21 are currently available in the market and can significantly reduce emissions 

associated with pressure vacuum vents. Chapter 7 of the tank study in Appendix F of this report 

provides several sources of information that can be used to estimate the emission inventory for 

pressure vacuum vents. Depending on assumptions used, the emission inventory from pressure 

vacuum vents potentially can be significant. District staff has used a factor of 0.1 tons per year 

per vent to estimate the emission reductions associated with pressure vacuum vents. Testing to 

verify this factor was done as described in Section B-5 of Appendix B. 
Chapter 5 – Emissions Reduction Final Staff Report

Proposed Rule 1178 21 December 11, 2001 

Table 5-1 – Control Options and Emission Reduction Estimates

Tank 

Type 

Control Option No of Tank Effected Emission Reduction 

Estimates 

External 

Floating 

Roof 

Tanks 

Upgrading Rim Seals – Using 1) mechanical or 

liquid-mounted primary seals and rim-mounted 

secondary seals for welded tanks and 2) 

mechanical shoe primary seals and rim-mounted 

secondary seals for riveted tanks. 

9 

(6 from refineries, and 

3 from non refineries) 

4.01 tpy (0.01 tpd) 

(2.55 tpy from 

refineries, and 1.46 tpy 

from non-refineries ) 

External 

and 

Internal 

Floating 

Roof 

Tanks 

Upgrading Deck Fittings – Using 1) bolted and 

gasketed components such as access hatches, 

gauge float wells, rim vents etc. 2) slotted 

guidepoles/wells with gaskested sliding covers, 

floats, pole sleeves, and pole wipers; or 3) 

unslotted guidepoles with gasketed sliding covers 

and pole wipers. 

 65.75 tpy (0.18 tpd) 

(18.95 tpy from 

refineries, and 46.80 

tpy from nonrefineries) 

External 

Floating 

Roof 

Tanks 

Installing Domed or Fixed Roofs – On external 

floating roof tanks containing materials with TVP 

>≥3 psia, excluding crude oil tanks. 

241195 5

(146118 from 

refineries, and 9577

from non-refineries) 

348.27 324.21 tpy 

(0.95 0.89 tpd) 

(0.207.41 189.47 tpy 

from refineries and 

140.86 134.74 tpy 

from non-refineries) 

Fixed 

Roof 

Tanks 

Venting to vapor control system or vapor 

recovery system or converting to internal 

floating roof tanks. 

70 

(19 from refineries and 

51 from nonrefineries) 

62.71 tpy (0.17 tpd) 

(36.55 tpy from 

refineries and 26.16 

tpy from nonrefineries) 

Fixed 

Roof 

Tanks 

Maintaining pressure vacuum vents to achieve 

500 ppm leakage rate.

532 

(308 from refineries 

and 224 from nonrefineries) 

53.20 tpy (0.15 tpd) 

TOTAL

533.94 tpy (1.46 tpd) including doming crude 

oil tanks

509.88 tpy (1.40 tpd) excluding doming crude 

oil tanks

 

5

The current 1999-2000 inventory submitted showed that there were 28 crude oil tanks located at refineries and 18 at nonrefineries. The emission reductions associated with these tanks were estimated to be 17.94 tpy and 6.12 tpy, respectively.
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 22 December 11, 2001 

Chapter 6 – Cost and Cost Effectiveness Analysis 

Cost Information 

Upgrading Rim Seals 

Several refineries provided District staff with cost information for upgrading existing rim seal 

systems. In addition to the information provided by the refineries, District staff has gathered cost 

information from two manufacturers of primary and secondary seals. The cost is provided in 

Table 6-1. 

Table 6-1 - Cost for Upgrading Rim Seals 

Refinery or 

Manufacturer 

Replacing Rule 463 Rim Seal 

B/C with A 

Replacing with “tight 

fitting” seal (Note (a)) 

Refinery #1 $1,500 per foot $1,500 per foot 

Refinery #3 $40,000 per tank (Note (b)) No data 

Refinery #5 $135 per foot $115 per foot 

Manufacturer #1 Materials: $57 per foot for primary, $74 per foot for secondary. 

Installation: $64 per foot for installation cost including removal 

of existing seals and installing new primary and secondary seals. 

(Note (c)) 

Manufacturer #2 Materials: $45 per foot for primary, $25 per foot for secondary. 

Installation: $28 per foot for primary, $13 per foot for secondary, 

$19 per foot removal existing seals. 

Note: (a) Tight fitting seals are seals that provide tight fitting with no gaps more than 1/8 inch wide between the seal 

and the tank shell. (b) For primary seal only. Do not have data on secondary seal. (c) Replacing seals can be 

performed with tanks remaining in-service. 

Upgrading Deck Fittings 

Several refineries provided District staff with cost information for upgrading deck fittings. 

Upgrading deck fittings means installing gaskets, seals, pole sleeves, pole wipers and/or covers 

for deck fittings on internal and external floating roof tanks. The cost information provided by 

the refineries is summarized in Table 6-2. 
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 23 December 11, 2001 

Table 6-2 - Cost for Upgrading Deck Fittings 

Refinery For slotted and unslotted 

guidepoles and wells 

For other deck fittings 

1 $4,500 per fitting $500 per fitting 

3 $10,000 (Note (a)) $60 per each leg cover (Note (b)) 

5 $2,400 - $6,000 per tank (Note c)) $850 per tank 

Note: (a) Including installation costs. (b) Assuming 24 legs per tank. (c) $2,400 for gaskets, floats and wipers; 

$6,000 for pole sleeves. 

Domed Roofs 

Several refineries provided District staff with cost information for installing a domed roof on 

external floating roof tanks. The information is summarized in Table 6-3. In addition to the 

information provided by the refineries, District staff has gathered cost information from three 

manufacturers of geodesic domed roofs. The cost is provided in Figure 6-1. 

Table 6-3 - Cost for Geodesic Domed Roofs 

Refinery Cost 

3 $200,000 per 120 ft tank

5 $19,700 (25 ft diameter tank) to $746,600 (218 ft diameter tank) 

(Note (a)) 

Note: (a) This cost does not include cost of emptying, purging and refloating the tank. 

Internal Floating Roof Tanks 

There are 19 fixed roof tanks at refineries and 51 at non-refineries currently vented to the 

atmosphere. Several refineries provided District staff with cost information for converting a 

fixed roof tank to an internal floating roof tank. The information provided by the refineries, and 

gathered by District staff from a manufacturer isare summarized in Table 6-4. 

Table 6-4 - Cost for Internal Floating Roof Tanks 

Refinery Cost 

1 $1,100 per diameter foot (Note (a))

3 $100,000 per tank

5 $25 per square foot

Manufacturer $42K for 30 ft diameter tank; $58K for 50 ft diameter; $71K for 

60 ft diameter; $125K for 120 ft diameter; $201K for 150 ft 

diameter; and $315K for 200 ft diameter tank.

Note: (a) Does not include costs associated with taking tank out-of-service, degassing, and cleaning the tank. 
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 24 December 11, 2001 

Figure 6-1- Cost of Domed Roofs for External Floating Roof Tanks 

Vapor Control and Vapor Recovery System 

There are 19 fixed roof tanks at refineries and 51 at non-refineries currently vented to the 

atmosphere. In lieu of converting the fixed roof tanks to internal floating roof tanks, the operator 

may choose to vent the vapor losses from these fixed roof tanks to a vapor control system or a 

vapor recovery system. An existing vapor control or vapor recovery system on site may be able 

to carry the additional load. In this scenario, the cost effectiveness of this control option is 

negligible. The cost effectiveness however could vary significantly with each individual 

scenario depending on the location of the tanks, the size of the existing compressors, and the 

types of vapor control or vapor recovery system the facility would choose to use. Because of 

that reason, to evaluate the cost effectiveness for the entire Proposed Rule 1178, District staff 

would use the cost effectivess derived for internal floating roof tanks. 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

59 91 117 120 133 139 143 150 218

Tank Diameter (ft)

Cost As Installed ($)

Manufacturer #1 Manufacturer #2 Manufacturer #3
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 25 December 11, 2001 

Pressure Vacuum Vents 

Several refineries and manufacturers have provided District staff with cost information as shown 

in Table 6-5 for installing pressure vacuum vents that meet 500 ppm limit. 

Table 6-5 - Cost for Pressure-Vacuum Vents 

Refinery/Manufacturer Cost 

3 $7,000 to $10,000 for each PV vent depending on size

5 $2,500 for each 4” to 6” PV vent

Manufacturers $350 to $10,000 for each PV vent depending on size

Cost Effectiveness Analysis 

District staff has estimated a cost effectiveness factor for the Proposed Rule 1178. The cost 

effectiveness for the Proposed Rule 1178 is shown in Table 6-6. Scenario 1Staff Proposal 

(Scenario 1) reflects the impacts of implementing the requirements of the Proposed Rule 1178. 

Specifically, Scenario 1 considered the impacts of:

• Upgrading rim seals and deck fittings on all internal and external floating roof tanks 

containing materials with true vapor pressures > 0.1 psia; 

• Installing domed roofs on all external floating roof tanks containing materials with true vapor 

pressures >≥ 3 psia, excluding crude oil tanks; 

• Converting fixed roof tanks containing materials with true vapor pressures > 0.1 psia 

currently vented to the atmosphere to internal floating roof tanks; and 

• Maintaining all pressure vacuum vents to meet 500 ppm standard. 

The cost effectiveness factor was based on the following assumptions: 

Upgrading Rim Seals 

• Number of tanks having primary seals that need upgrading was 3. Number of tanks having 

secondary seals that need upgrading was 9. 

• Average tank diameter was 127 ft for the universe of tanks in this category. 

• Average cost per linear foot of primary seal was $107, and secondary seal was $98, as 

installed. 

• Sales taxes were calculated as 8% cost of rim seals. 

• Capital cost included cost of rim seals as installed and sale tax. 
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 26 December 11, 2001 

• Annual maintenance cost was estimated based on an assumption that it takes one man to 

work on one tank for 8 hours at a labor rate of $30/hour. 

• Product savings were estimated based on $200/ton emissions. The $200/ton was derived 

based on an estimated product cost of $0.5 per gallon and a liquid density of 5 lbs/gal for 

gasoline. 

• Annual operating cost included annual maintenance cost and product savings. 

• Total present worth was determined based on discounted cash flow method with an 

assumption of 4% real interest rate, and a 10 year average life of the rim seal system. 

• Total emission reduction for this control option was approximately 4.01 tpy. 

Upgrading Deck Fittings 

• Number of guidepoles that need upgrading was 274, number of other fittings that need 

upgrading was 6,281 for external floating roof tanks. For internal floating roof tanks, the 

numbers were 172 for guidepoles and 1,057 for other fittings. 

• Cost of upgrading a guidepole was $10,000 including installation cost. 

• Cost of upgrading other fittings was $500 per fitting with an installation cost equal to 10% of 

the cost of upgrading each fitting. 

• Sales taxes were calculated as 8% cost of fittings.

• Capital cost included cost of upgrading fittings, guidepoles, installation costs, and taxes 

• Annual maintenance cost was estimated based on an assumption that it takes one man to 

work on one tank for 8 hours at a labor rate of $30/hour. 

• Product savings were estimated based on $200/ton emissions. The $200/ton was derived 

based on an estimated product cost of $0.5 per gallon and a liquid density of 5 lbs/gal for 

gasoline. 

• Annual operating cost included annual maintenance cost and product savings. 

• Total present worth was determined based on discounted cash flow method with an 

assumption of 4% real interest rate, and a 10 year average life of gaskets, wipers etc. for the 

roof fittings. 

• Total emission reduction for this control option was approximately 25.31 tpy from external 

floating roof tanks, and 40.44 tpy from internal floating roof tanks. 
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 27 December 11, 2001 

Table 6-6 – Cost Effectiveness and Incremental Cost Effectiveness 

Estimates ($/ton VOC reduced) for Proposed Rule 1178 

Scenario 

External Floating Roof Tanks Internal Floating Roof 

Tanks 

Fixed Roof Tanks 

Upgrading 

Rim Seals 

Upgrading 

Deck 

Fittings 

Installing 

Domed 

Roofs 

Upgrading 

Rim Seals 

Upgrading 

Deck Fittings

Converting 

to IFRTs 

PV Vents 

Staff Proposal (Scenario 1)

Description Control Up 

to 0.1 psia

Control All Control Up to 

3 psia, 

excluding 

crude oil 

tanks

No Control Control All Control Up to 

0.1 psia 

Control Up 

to 0.1 psia

No of 

Tanks/Fittings

 9 6,555 241195

(Note 7)

0 1,229 70 532 

Emi 

Reduction 

tpy 4.01 25.31 34824.271 0 40.44 62.71 53.20 

Present 

Worth Value 

$ 529,388 6,625,884 84,094,14559

,292,230

0 2,417,583 15,140,237 2,070,970 

Cost 

Effectiveness 

Factor for 

Individual 

Control 

Option 

$/ton 13,202 26,179 12,0739,144

(Note 1, 2, 3)

0 5,978 12,072 3,893 

Overall Cost 

Effectiveness 

Factor 

$/ton 11,473 9,583 (Note 4, 5)

The Most Stringent Proposal (Scenario 2)

Description Control All Control All Control All Control All Control All Control All Control All 

No of 

Tanks/Fittings

 66 7,539 526 198 1,393 296 532 

Emi 

Reduction 

tpy 11.67 25.31 365.69 14.14 40.44 142.00 53.20 

Present 

Worth Value 

$ 3,034,926 7,339,174 158,917,205

172,734,311

6,863,178 2,657,283 64,356,360 2,070,970 

Cost 

Effectiveness 

Factor for 

Individual 

Control 

Option 

$/ton 26,006 28,997 21,72823,618

(Note 1, 2, 3)

48,537 6,571 22,661 3,893 

Overall Cost 

Effectiveness 

Factor 

$/ton 19,855 21,536 (Note 4, 5)

Incremental 

Cost 

Effectiveness 

Factor 

$/ton 113,375 121,330 (Note 4, 6)
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 28 December 11, 2001 

Note:

1. For Staff Proposal (Scenario 1), the cost effectiveness of $9,144 per ton VOC reduced represents the doming of 195 external 

floating roof tanks containing materials with TVP ≥ 3 psia at refineries and non-refineries, excluding crude oil tanks. For 

the most stringent proposal (Scenario 2), the cost effectiveness of $23,618 per ton VOC reduced represents the doming of 

526 external floating roof tanks containing materials with TVP ≥ 3 psia at refineries and non-refineries, including crude oil 

tanks. The cost effectiveness for tanks containing crude oils was estimated about $62,000 per ton VOC reduced.

2. For doming, the cost effectiveness in Staff Proposal (Scenario 1) and the most stringent proposal (Scenario 2) includes cost 

of domed roofs as installed, cost for obtaining permits, project management cost, loss-of-use cost, annual maintenance cost, 

annual insurance and property taxes, annual emission savings, product savings, and self-inspection savings.

3. The risk of having fire on domed external floating roof tanks and internal floating roof tanks is lower than on external 

floating roof tanks. However, an extreme worst case scenario would include fire suppression system on all domed external 

floating roof tanks. District staff had performed an analysis including the cost of installing a fire suppression system and 

maintenance costs associated with such system. For Staff Proposal (Scenario 1), the cost effectiveness factor for this 

extreme worst case analysis is $11,332 per ton VOC reduced in comparison to $9,144 per ton VOC reduced where the cost 

of fire suppression is not included. For the most stringent proposal (Scenario 2), the cost effectiveness factor for this 

extreme worst case analysis is $28,850 per ton VOC reduced in comparison to $23,618 per ton VOC reduced where the cost 

of fire suppression is not included. 

4. Under the extreme worst case scenario where the cost of fire suppression system is included, the overall cost effectiveness 

factor is $10,974 per ton VOC reduced for Staff Proposal (Scenario 1) in comparison to $9,583 per ton VOC reduced where 

the cost of fire suppression is not included. For the most stringent proposal (Scenario 2), the overall cost effectiveness factor 

is $24,468 per ton reduced in comparison to $21,536 per ton VOC reduced where the cost of fire suppression is not 

included. The incremental cost effectiveness factor is $138,220 per ton VOC reduced for the extreme worst case scenario in 

comparison to $121,330 per ton VOC reduced where the cost of fire suppression is not included. 

5. The overall cost estimate factor is calculated as follows: [(2 x Sum of All Present Worth Values of the Control Options that 

Have 10-Year Life) + (Sum of All Present Worth Values of the Control Options that Have 20-Year Life)] / [(Emission 

Reductions Provided by All Control Options) * 20 Years]

6. The incremental cost effectiveness factor is calculated as follows: [Total Present Worth Values of All Control Options in the 

most stringent proposal (Scenario 2) - Total Present Worth Values of All Control Options in Staff Proposal (Scenario 1)] / 

[Total Emission Reductions from the most stringent proposal (Scenario 2) - Total Emission Reductions from Staff Proposal 

(Scenario 1)]

7. The count of 195 tanks includes 10 tanks at small refiners, refer to Table B-6 of Appendix B

Internal Floating Roofs 

• Number of fixed roof tanks that need to be converted was 19 tanks at refineries and 51 tanks 

at non-refineries with tank diameters from 30 ft to 120 ft. 

• Total cost as installed for the 70 tanks with various tank diameters was $10,728,421. This 

cost includes the costs of double wiper primary and secondary rim seal systems.

• Sales taxes, freight, engineering, and installation costs were included in total cost as installed. 

• A cost for not being able to use the tanks during the construction of the internal floating roofs 

were estimated as 40% of equipment cost, based on data provided for dome roof installation. 

• Annual maintenance cost was estimated at 3% equipment cost. 

• Annual insurance was estimated at 1% capital cost. 

Formatted: Bullets and Numbering
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 29 December 11, 2001 

• Product savings were estimated based on $200/ton emissions. The $200/ton was derived 

based on an estimated product cost of $0.5 per gallon and a liquid density of 5 lbs/gal for 

gasoline. 

• Annual operating cost included annual maintenance cost, annual insurance and product 

savings. 

• Total present worth was determined based on discounted cash flow method with an 

assumption of 4% real interest rate, and a 20 year average life of the internal floating roofs. 

• Total emission reduction for this control option was approximately 62.71 tpy. 

Domed Roofs 

• Number of tanks that need domed roofs was 146 at refineries and 95 at non-refineries with 

tank diameters from 30 ft to 260 ft. Excluding 46 crude oil tanks, the total number of tanks 

that need domed roofs was 195.

• Total cost as installed for the 241 tanks with various tank diameters was $49,780,993. 

Excluding 46 crude oil tanks, the cost as installed was $33,594,943. The costs provided by 

Manufacturer #1 include tank surveys, engineering design and drawings stamped by 

professional engineers registered in California, materials, fabrication, sales taxes, freight, site 

unloading materials and handling, insurance, and complete installation with appropriate 

license. The costs include at least 10% contingency for unusual work such as modification of 

tank platforms.

• Sales taxes at 8% and freight were included in the cost as installed as provided by the three 

manufacturers of domed roofs. 

• Cost for permit application was estimated based on a unit cost of $2,115 per application. 

Note that when applications for doming were to be submitted as a group, cost for permit 

processing could be reduced.

• Project management was estimated as 5% of equipment cost.

• Capital cost included cost of equipment cost, sale taxes, and freight, and project 

management. 

• It was assumed that domed roofs were installed while the tanks were still. A cost for not 

being able to use the tanks during the construction of the domed roofs was estimated based 

on the days of construction provided by the manufacturers, and a lease rate for storage of 1.5 

cents per barrels per day provided by the refineries. The assumption that construction of a 

domed roof occurs in 24 hours a day, 7 days a week may overestimate the real cost because 

the construction of the domed roof typically occurs in 8 hours a day and 5 days a week. 

• Annual maintenance cost was estimated at 1% equipment cost. 

Formatted: Bullets and Numbering
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 30 December 11, 2001 

• Annual insurance and property tax was estimated at 12% capital cost. It should be noted that 

this was a conservative estimate because depreciation was not taken into account.

• Product savings were estimated based on $200/ton emissions. The $200/ton was derived 

based on an estimated product cost of $0.5 per gallon and a liquid density of 5 lbs/gal for 

gasoline. 

• Annual emission savings were estimated at $819.11 per ton emissions.

• Inspection savings were estimated assuming that the inspection for rim seals and deck fittings 

on external floating roof tanks was reduced with the installation of domed roofs. It was 

based on 8 hr/day for 3 tanks at $30 per hour.

• Annual operating cost included annual maintenance cost, annual insurance, annual emission 

savings, inspection savings and product savings. Note that savings resulting from other 

benefits of installing domed roofs such as protecting the products from contamination, or 

reducing the costs of replacing rim seals system were not included.

• Total present worth was determined based on discounted cash flow method with an 

assumption of 4% real interest rate, and a 20 year average life of the domed roofs. 

• Total emission reduction for this control option was approximately 348.27324.21 tpy

excluding crude oil tanks. 

Pressure Vacuum Vents 

• The emission reduction from PV vents was approximately 0.1 tpy per vent. 

• Annual maintenance cost was estimated at $500 per vent. 

• Product savings were estimated based on $200/ton emissions. The $200/ton was derived 

based on an estimated product cost of $0.5 per gallon and a liquid density of 5 lbs/gal for 

gasoline. 

• Annual operating cost included annual maintenance cost and product savings. 

• Total present worth was determined based on discounted cash flow method with an 

assumption of 4% real interest rate, and a 10 year average life of a PV vent. 

The overall cost effectiveness factor for Scenario 1Staff Proposal (Scenario 1) was estimated to 

be $11,4739,583/ton VOC reduced. The cost effectiveness factor in Table 6-6 shows that the 

Proposed Rule 1178 is cost effective. 

Incremental Cost Effectiveness Analysis 

To determine the incremental cost effectiveness of the most a more stringent control scenario, 

required under state law, staff has also considered Scenario 2the most stringent proposal 

Formatted: Bullets and Numbering
Chapter 6 – Cost and Cost Effectiveness Analysis Final Staff Report

Proposed Rule 1178 31 December 11, 2001 

(Scenario 2). Specifically, Scenario 2the most stringent proposal (Scenario 2) reflects the 

impacts of implementing the following technically feasible control strategies: 

• Upgrading rim seals and deck fittings on all internal and external floating roof tanks; 

• Installing domed roofs on all external floating roof tanks; 

• Converting all fixed roof tanks currently vented to the atmosphere to internal floating roof 

tanks; and 

• Maintaining all pressure vacuum vents with vents that meet the 500 ppm leak standard. 

The cost effectiveness for Scenario 2the most stringent proposal (Scenario 2) was approximately 

$19,85521,536 per/ ton VOC reduced, and the incremental cost effectiveness of Scenario 2the 

most stringent proposal (Scenario 2) compared to Scenario 1Staff Proposal (Scenario 1) is 

approximately $113,375121,330 per /ton VOC reduced. 
Impact Assessment Final Staff Report 

Proposed Rule 1178 32 December 11, 2001 

Chapter 7 – Impact Assessment 

Environmental Impact Assessment 

Pursuant to the California Environmental Quality Act (CEQA) and AQMD Rule 110, 

appropriate CEQA documentation has been prepared for proposed Rule 1178 and is currently 

circulated for review. Comments received will be addressed when evaluating the potential for 

adverse environmental impacts from the proposal, and will be incorporated into the final 

document for PR1178. 

Socioeconomic Assessment 

A socioeconomic assessment is included as addendum to this staff draft staff report.. will be 

incorporated into the final document for PR1178.

Disruption of Production 

As shown in AttachmentAppendix D, in November, District staff has analyzed the issue of 

removing storage capacity as a result of the requirement to install domes on existing external 

floating roof tanks. Separate analyses have been conducted for refineries and non-refineries, and 

for the capacity removal potential as well as the tank removal potential. The number of tanks 

and potential domed tanks in Table D-1 and Table D-2 of Appendix D includes crude oil tanks. 

Refineries 

 Tank Removal Percentage 

As shown in Table D-1 of Appendix Attachment D, the total number of external floating roof 

tanks at seven major refineries is 383, including crude oil tanks. The number of potential domed 

tanks at these refineries is about 136 tanks in a period of four years. Each year, the 7 refineries 

are expected to dome 34 tanks, or on average each refinery is expected to dome 5 tanks. The 

potential tank removal is therefore approximately (34 tanks/383 tanks) = 9% during the doming 

period. 

The doming period varies according to the tank's size, which is approximately about 11 days for 

a 70 ft diameter tank, 25 days for a 150 ft diameter tank, to a maximum of 63 days for a 260 ft 

diameter tank. About 80% of tanks in the refineries required doming are in the group of tanks 

that have diameter of about 150 ft; 10% of tanks have less than 100 ft diameter; and 10% of 

tanks have diameter more than 200 ft. The average doming period is approximately about 30 

days (i.e. (25 days * 0.8) + (11 days * 0.1) + (63 days * 0.1). In that 30 days (8% of the entire 

365 days), it is expected that the refineries will loose about 10% of the external floating roof 

tanks (Figure D-4) at the site for doming. When all types of tanks are considered, including 

fixed roof tanks, external floating roof tanks, and internal floating roof tanks, the tank removal 

percentage drops to 5% (Figure D-3). 
Impact Assessment Final Staff Report 

Proposed Rule 1178 33 December 11, 2001 

Refineries indicated that tanks at refineries were usually removed for routine maintenance 

following a schedule specified under API 653, "Tank Inspection, Repair, Alteration, and 

Reconstruction". A typical inspection schedule for tank bottoms recommended in API 653 is 

between 10 to 20 years depending on whether or not the corrosion rate of the tank bottom is 

known. Assuming that an average routine maintenance schedule is 15 years and that all types of 

tanks would be removed at the same rate, then approximately 26 external floating roof tanks (383 

total external floating roof tanks / 15 year = 26 tanks/year) are expected to be removed from 

service in any one year for the 7 refineries for routine maintenance. If the doming schedule of 

the PR1178 was expanded to 6 years, the average doming rate would become 23 tanks/year, 

which is less than the average rate of removal tanks for routine maintenance. 

In December, upon recommendations received from industry, District staff has proposed to 

exempt crude oil tanks from the doming requirements, and provide an implementation period of 

6 years instead of 4 years. When these two factors are taken into the analysis, the tank removal

percentage drops from 10% (Figure D-4) to 6% (Table D-3).

 Capacity Removal Percentage 

In November, aAn analysis has been done for capacity removal by looking at the capacity of all 

the tanks at the refineries. During the four year period to dome these external floating roof tanks, 

approximately 1.13% (on average) (Figure D-1) of the total storage capacity could be taken out 

of service at any one time when the capacity of all the types of tanks at refineries are considered. 

The loss of capacity ranges from 0.12% to 2.15% for the 7 refineries. When capacity of only

external floating roof tanks are considered, the average capacity removal percentage is 1.66 

(Figure D-2).

In December, upon recommendations received from industry, District staff has proposed to 

exempt crude oil tanks from the doming requirements, and provide an implementation period of 

6 years instead of 4 years. When these two factors are taken into the analysis, the capacity 

removal percentage drops from 1.66% (Figure D-2) to 0.6% (Table D-3).

Non-refineries 

 Tank Removal Percentage 

Staff’s analysis of non-refineries (tank farms and loading racks) indicates a greater percentage of 

lost tank capacity. During the four year period to dome these external floating roof tanks, 

approximately 10% (on average) (Figure D-7) of the total tanks could be taken out of service at

any one time when all types of tanks are considered. The percentage will increase to 201% when 

only external floating roof tanks are considered (Figure D-8). The tank removal percentage 

ranges from 3% to 25% for the 14 non-refineries. 

In December, upon recommendations received from industry, District staff has proposed to 

exempt crude oil tanks from the doming requirements, and provide an implementation period of 

6 years instead of 4 years. When these two factors are taken into the analysis, the tank removal 

percentage drops from 21% (Figure D-8) to 14% (Table D-4).
Impact Assessment Final Staff Report 

Proposed Rule 1178 34 December 11, 2001 

 Capacity Removal Percentage 

Staff’s analysis of non-refineries (tank farms and loading racks) indicates a slightly greater 

percentage of lost storage tank capacity. During the four year period to dome these external 

floating roof tanks, approximately 1.33% (on average) (Figure D-5) of the total storage capacity 

of all tanks could be taken out of service at any one time. The loss of capacity ranges from 

0.14% to 3.27% for the 14 non-refineries. The percentage will increase to 2.47% (Figure D-6)

when only external floating roof tanks are considered.

In December, upon recommendations received from industry, District staff has proposed to 

exempt crude oil tanks from the doming requirements, and provide an implementation period of 

6 years instead of 4 years. When these two factors are taken into the analysis, the capacity 

removal percentage drops from 2.47% (Figure D-6) to 1.67%.

Gasoline Cost Impact to Consumer

Implementation of PR1178 would result in an expenditure of approximately $86 million (i.e. the 

total present worth values estimated for all control strategies in Staff Proposal (Scenario 1) of 

Table 6-6). The amount of gasoline dispensing in the District is about 6 billion gallons per year 

(Reference: Staff Report of Amended Rule 461 - "Gasoline Transfer and Dispensing", April 14, 

2000). If the cost of implementing the PR1178 is passed on to the consumers, the consumers are 

expected to pay an increase of approximately 0.23 cents per gallon in gasoline cost during the 

six years of Phase I of the rule, or an increase of 0.07 cents per gallon if the cost is amortized 

over the 20-year life of the project.

With a similar approach, the control strategy of doming as suggested in the PR1178 would result 

in an expenditure of approximately $59 million; this is approximately equivalent to an increase 

of 0.16 cents in gasoline cost during the six years of Phase I of the rule, or an increase of 0.05

cents per gallon if the cost is amortized over the 20-year life of the project.

 

 

Comparative Analysis 

Under the Health and Safety Code Section 40727.2, the District is required to compare and 

analyze this Proposed Rule 1178 with existing state or federal regulations. This analysis is 

attached in the Appendix E of this Draft Staff Report. 

Draft Findings Required by the California Health and Safety Code

Under the Health and Safety Code Section 40727, the District’s Governing Board is required to 

make findings of necessity, authority, clarity, consistency, nonduplication, and reference before 

adopting a rule, such as Proposed Rule 1178.
Impact Assessment Final Staff Report 

Proposed Rule 1178 35 December 11, 2001 

Necessity: The District’s Governing Board has determined that a need exists to adopt Proposed 

Rule 1178 to implement control measure FUG03, FUG04, and FUG05 in the 1999 AQMP.

Authority: The District obtains its authority to adopt, amend or repeal rules and regulations 

from Sections 39002, 40000, 40001, 40440, 40702, and 41508 of the California Health and 

Safety Code.

Clarity: The District’s Governing Board finds and determines that Proposed Rule 1178 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: The District’s Governing Board has determined that the Proposed Rule 1178 as 

proposed to be adopted is in harmony with, and not in conflict with or contradictory to, existing 

statutes, court decisions, or state or federal regulations.

Nonduplication: The District’s Governing Board has determined that the Proposed Rule 1178 

as proposed to be adopted does not impose the same requirements as any existing state or federal 

regulation.

Reference – In adopting this proposed rule, the AQMD Governing Board references the 

following statutes, which AQMD hereby implements, interprets or makes specific. Health and 

Safety Code Sections 40000, 40001, 40440, and 40727.
Comments and Responses Final Staff Report 

Proposed Rule 1178 36 December 11, 2001 

Chapter 8 – Comments and Responses 

The following summarizes verbal and written comments received on and after the Public 

Workshop for PR1178. 

Applicability 

1-1 Comment 

It is proposed that the applicability of the rule to a facility be based on that facility having 

exceeded a threshold of 20 tons of VOC emissions in any reporting year beginning in 

1999. We believe that there are certain aspects of this applicability threshold that should 

be either clarified or changed. We submit that it is not reasonable for a facility to become 

subject to the rule by virtue of a one-year anomaly in emissions – especially in light of 

the potential need to temporarily increase throughput at one facility when tanks are taken 

off line at another facility in order to install controls mandated by this rule. Such 

unintended (and, we submit, punitive) consequences would be avoided if the applicability 

of the rule were based on exceeding the 20 ton/year threshold for five consecutive years. 

Response 

In 1999, the District settled litigation initiated by three environmental organizations, the 

Natural Resources Defense Council (NRDC), the Coalition for Clean Air, and the 

Communities for a Better Environment (CBE) for failing to implement the 1994 AQMP. 

The settlement agreement, which was incorporated in the 1999 AQMP amendments, in 

part, commits the AQMD to further study fugitive emissions from tanks and pressure 

relief devices (PRDs) operated by refineries and proceed with amendments to existing 

rules and/or the development of new rules in the event the study(ies) identify meaningful 

emission reduction potentials and technologically feasible and cost-effective controls. 

Also, AQMD Control Measure FUG-05 - Further Emission Reductions from Large 

Fugitive VOC Sources focuses on reducing fugitive emissions from the top 100 VOCemitting facilities. The top VOC-emitting facilities targeted in this control measure 

consist mainly of petroleum facilities that emit 20 tons or more per year, and this is not 

expected to change significantly from year to year. In addition, PR1178 is designed to 

implement the first phase of FUG-05. With respect to those facilities that trigger the 

applicability of PR1178 in the future due to an increase in throughput and emission and 

to accommodate the facility that takes tanks off-line to comply with the PR1178, staff is 

proposing an extended compliance schedule and the option to either dome or accept a 

permit condition for the facility's external floating roof tanks that may become subject to 

the rule (Subparagraph (d)(2)(B) and (d)(2)(C) of PR 1178). 

1-2 Comment 

The applicability determination should include a review of several years, rather than one 

year. As we understand it, once a facility is included it cannot be removed. The factors 

that contribute to our facilities’ emission inventory include tanks, fugitives and loading 

racks. The emissions from the loading racks can fluctuate from year to year depending 

on the results of the source test data. It is our understanding that the purpose of this rule 
Comments and Responses Final Staff Report 

Proposed Rule 1178 37 December 11, 2001 

is to reduce emissions from storage tanks, therefore, we would suggest that the 

applicability be based on emissions from the aboveground storage tanks exclusively over 

a five year period. We suggest consideration that if in a five year period the facility 

consistently has aboveground storage tank emissions of 20 tons or greater, then the 

facility would be included in 1173.1. (1178) 

Response 

Please refer to the Response to Comment 1-1. In addition, please note that PR1178 is 

implementing Phase I of the Control Measure FUG-05. Focuses on further reducing 

emissions from storage tanks operated by petroleum facilities in Phase II and Phase III 

will focus on other emission sources within the top VOC emission sources. Emission 

reductions of 1.47 tons per day of VOC based on a universe of facilities reporting total 

VOC emissions of 20 tons per year or greater. To lower the applicability threshold by 

looking only at tank emissions would require greater emission reductions from other 

fugitive sources at petroleum facilities to meet the goals of Control Measure FUG-05 and 

would leave out a number of high emitting VOC facilities. 

1-3 Comment 

We understand that the 20-ton hurdle to identify tanks that are subject to the new rule was 

selected because it limited the number of facilities affected at this time. This is an 

inadequate justification. We recommend the hurdle be tied directly to tank emissions at a 

facility. The contribution of emissions from tanks may not correlate with entire facility 

emissions. A selection criteria of 10 tons per year of VOC from tank emissions, 

borrowing the 10 tons from the definition of a major source in the SCAQMD, is a 

recommended alternative to identify whether a facility is in the program or out of the 

program. 

Response

Please refer to Responses to Comment 1-1 and 1-2. In addition, the definition of a major 

source is based on total facility emissions and not limited to a specific equipment 

categoty within a facility. 

1-4 Comment 

Use AQMD Rule 463 applicability standards. While we appreciate the simplicity of the 

language (tanks greater than 19,815 gallons storing organic liquids with a TVP greater 

than 0.1 psia) the Rule establishes another distinct layer of complexity in determining 

which rules apply to which tanks. We currently have tanks regulated by MACT, NSPS, 

NESHAP and AQMD Rule 463. For the sake of consistency with Rule 463, which was 

often indicated by District staff as a goal in developing the proposed Rule, we would 

appreciate similar language for tank applicability. That is, for tanks larger than 39,630 
Comments and Responses Final Staff Report 

Proposed Rule 1178 38 December 11, 2001 

gallons the triggering TVP would be ≥ 0.5 psia and for tanks greater than 19,815 gallons

the triggering TVP would be ≥ 1.5 psia [Rule 463(c)]. 

Response

The purpose of this proposed rule is to “further” (emphasis added) reduce volatile organic 

compounds emissions from storage tanks located at petroleum facilities. To use Rule 463 

applicability standards would not achieve the emission reduction goals associated with 

the Control Measure FUG-05 (see Response to Comment 1-1 and 1-2). 

1-5 Comment 

As written, the Rule has no provisions for facilities that may come into the program late. 

A facility with just under 20 tons/year emissions will not be subject to the Rule. If either 

through growth or changes in correlation equations for emissions, the facility later 

exceeds the 20 tons/year, what time frame will they be subject to for implementing the 

Rule? 

Response

Staff has added rule language to address this issue. Please refer to PR1178 (d)(5). 

1-6 Comment 

Rule applicability is based on vapor pressure, however vapor pressure can vary for the 

same product over the course of the year, depending on temperature, etc. Will the true 

vapor pressure be based on an annual average or based on the highest vapor pressure at 

some maximum temperature? The use of a maximum vapor pressure from a single 

measurement could cause tanks normally exempt to be captured by the rule. 

Response 

Staff has included rule language to clarify that rule applicability for doming will be based 

on the true vapor pressure at average storage temperature of 750 degrees F. 

1-7 Comment 

A facility has overall VOC emissions greater than 20 tpy and is included in the program. 

Later on the facility reduces its emissions below the 20 tpy limit. Will the facility be 

removed from the program? 

Response 

Once it is established that a facility has satisfied the criteria to be included in the 

program, the facility will not be removed from the program. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 39 December 11, 2001 

1-8 Comment 

Oil and gas producers are required to report emissions for unpermitted equipment such as 

well heads and well cellars. To quantify the emissions from these sources very 

conservative default emission factors (provided by the District) were used. Will the 

District provide us with a list of all applicable facilities and will facilities be allowed to 

go back and revise these emissions? 

Response 

Regulation 3 allows a facility to use source testing or other reliable information to revise 

the emissions reported to the District. In addition, Rule 1178 staff report will include a 

list of all facilities initially included in the program. That is based on reported emissions 

to the District. 

1-9 Comment 

Replace the compliance plan with a requirement to submit a notification of compliance 

status report at each milestone in the compliance schedule. 

Response 

Staff has amended rule language to address this issue by requiring an annual status report. 

Please refer to PR1178 (d)(2)(EG). 

1-10 Comment 

The proposed Rule, while claiming credit for AQMP control measures FUG-03, FUG-04, 

and FUG-05, has an approach, which often displaces the overall goal of reducing 

emissions. For example, the reduction claimed in the Rule based on seal location (vaporvs. liquid-mounted) has no technical argument which supports a reduction in emissions. 

The Vapor Tight Condition as defined in the Rule also has no emission reduction benefit. 

We recommend the District to reconsider their focus in these areas since real emission 

reductions from them are suspect. 

Response 

The issue regarding the terminology used to describe the types of primary and secondary 

seals has been clarified and incorporated into proposed rule language. Staff disagrees 

with the comment that the vapor tight condition (requirement) has no emission reduction 

benefit. The purpose of establishing a fugitive leak level of 500 PPM VOC is to reduce 

emissions through increased monitoring and maintenance. Staff has inspected, 

monitored, tested, and analyzed several roof openings associated with storage tanks and 

measured VOC concentrations in excess of 100,000 PPM, which was equivalent to an 

emission rate of approximately 9 pounds per hour. A qualitative assessment (based on the 

“dirt” build-up) was that some of the roof openings had not been maintained in quite 

some time. In addition, measuring for the vapor tight condition (as per EPA Method 21) 

provides operators with an alternative to measuring gaps for gaskets and/or seals, etc.. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 40 December 11, 2001 

Definitions 

2.1 Comment 

The definition of guidepole needs to be more broadly applicable. The definition should 

be revised as follows: The Guidepole is an anti-rotation device that is fixed to the top and 

the bottom of the tank, passing through a well that is equipped with a sliding cover. The 

guidepole may be used to prevent adverse movement of the roof and subsequent damage 

to the roof fittings and rim seals, or as access for level gauging or sampling of the liquid 

stock. The guidepole can be solid or equipped with slots or holes for gauging purposes. 

Response 

District staff has considered the recommendation, however the word "may be" creates 

uncertainty in the definition, therefore will not be used. The definition has been revised to 

incorporate the comments above.

2.2 Comment 

In the definition of Liquid-Mounted Primary Seal, the reference to mechanical shoe seal 

should be deleted, since a mechanical shoe seal is distinctly separate from either liquidmounted or vapor-mounted rim seal and each type of seal is assigned a separate and 

specific emission factor by the U.S. EPA in the Tanks 4.0 software for estimating 

emissions. The definition should read as follows: Liquid Mounted Primary Seal is a 

primary seal that is mounted in full contact with the liquid in the annular space between 

the tank shell and the floating roof. 

Response 

The definition has been revised to incorporate the comments above. 

2.3 Comment 

In the definition of Vapor-Mounted Primary Seal, the reference to mechanical shoe seal 

should be deleted, since a mechanical shoe seal is distinctly separate from either a vapormounted or a liquid-mounted rim seal and each type of seal is assigned a separate and 

specific emission factor by the U.S. EPA in the Tanks 4.0 software for estimating 

emissions. The definition should read as follows: Vapor-Mounted Primary Seal is a 

primary seal that does not come in contact with the liquid in the annular space between 

the tank shell and the floating roof. 

Response 

The definition has been revised to incorporate the comments above. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 41 December 11, 2001 

2.4 Comment 

The Pole Float definition should have broader applicability and should read as follows: 

Pole Float is device located inside a guidepole, which floats on the surface of the stored 

liquid and may be used to indicate the liquid level inside the tank. 

Response 

District staff has considered the recommendation, however the word "may be" creates 

uncertainty in the definition, therefore will not be used. The definition has been revised to 

incorporate the comments above.

2-5 Comment 

The definition of Pole Sleeve should be revised to incorporate a typographical error and 

should read as follows: Pole Sleeve is a device that extends from either the cover or the 

rim of an opening in a floating roof deck to the outer surface of a pole that passes through 

the opening. 

Response 

The definition has been revised to incorporate the comment above. 

2-6 Comment 

The definition of Pole Wiper should be revised to incorporate a typographical error and 

should read as follows: Pole Wiper is a seal that extends from either the cover or the rim 

of an opening in a floating roof deck to the outer surface of a pole that passes through the 

opening. 

Response 

The definition has been revised to incorporate the comment above. 

2-7 Comment 

The definition of Visible Gap should be revised to read as follows: Visible Gap is a gap 

of more than 1/8 inch between any gasket or seal and the opening that it is intended to 

seal. 

Response

The definition has been revised to incorporate the comment above. 

2-8 Comment 
Comments and Responses Final Staff Report 

Proposed Rule 1178 42 December 11, 2001 

The Roof Drain definition should be revised to indicate that the open roof type of drain is 

typically used only during emergency. 

Response 

The definition has been revised to incorporate the comment above.

2-9 Comment 

The Gauge Hatch/Sample Port definition should be revised to replace "self-closing" cover 

with "closing" and should be revised as follows: Gauge Hatch/Sample Port is an opening 

in the roof that provides access for gauging or sampling. The gauge hatch/sample port is 

usually equipped with a closing cover or a funnel and slit-fabric seal to cover the 

opening. 

Response 

The definition has been revised to incorporate the comment above. 

2-10 Comment 

The definition of Pressure-Vacuum Vent should be revised to include the safety features 

to prevent tank damage and should be revised as follows: Pressure-Vacuum Vent is a 

safety device designed to prevent damage to the tank and to minimize emissions due to 

breathing effects. 

Response 

District staff has considered the recommendation, however the word "safety device" 

creates uncertainty in the definition, therefore will not be used. The definition has been 

revised to incorporate the comment above.

2-11 Comment 

The definition of Primary Seal should be revised as follows: Primary Seal is a seal 

mounted below a secondary seal of a rim seal system. A primary seal, which slides in 

contact with the floating roof tank shell, can be mechanical shoe, resilient filled or wiper 

type. 

Response 

The definition will have "is" in place of "slides". The definition has been revised to 

incorporate the comment above.
Comments and Responses Final Staff Report 

Proposed Rule 1178 43 December 11, 2001 

2-12 Comment 

The definition for Resilient Filled Primary Seal should be revised as follows: Resilient 

Filled Primary Seal is an envelope filled with resilient foam (non-metallic polyurethane) 

mounted at the rim of the floating roof that makes contact with the shell. A resilient 

filled nonmetallic primary seal can be liquid-mounted or vapor-mounted. 

Response 

The definition has been revised to incorporate the comment above. 

2-13 Comment 

The definition of Rim Mounted Secondary Seal should be revised to exclude the portion 

that references the purpose of the secondary seal as an additional evaporative loss control 

device that compensates for defects in the primary seal fabric in emission losses. 

Response 

The definition of Rim Mounted Secondary Seal has been revised. 

2-14 Comment 

The definition of Rim Seal System should be revised as follows: Rim Seal System is a 

closure device between the shell of the storage tank and the floating roof edge. A rim 

seal may consist of two seals, one above the other. The lower seal is referred to as the 

primary seal and the upper seal is referred to as the secondary seal. 

Response 

The Rim Seal System definition has been revised to incorporate the comment above 

2-15 Comment 

The definition of Rim Vent should be revised as follows: Rim Vent is a device consisting 

of a weighted-pallet that rests on a valve seat. Rim vents are used to release any excess 

pressure or vacuum present in the vapor pocket between the seal and the rim area of a 

floating roof tank. 

Response 

The definition of Rim Vent has been revised to incorporate the comment. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 44 December 11, 2001 

2-16 Comment 

The definition of Roof Leg should be revised as follows: Roof Leg is a device that holds 

the floating roof at a predetermined distance from the tank bottom to allow for tank 

cleaning or repair. There are two types of roof legs, adjustable or fixed. Fixed roof legs 

are attached to the floating roof or to hangers suspended from the roof, whereas 

adjustable legs pass through a well or sleeve, and penetrate the roof. 

Response 

The definition of Roof Leg has been revised to incorporate the comment. 

2-17 Comment

Provide definitions for the terms “welded” and “riveted” tanks. The Rule is making a 

distinction between welded tanks and riveted tanks. We would appreciate defining 

language because we have tanks in service with both riveted and welded sections. 

However, we propose that the seal standard be consistent with riveted tanks because of 

potential damage rivets can have on seals. 

Response 

Staff has revised proposed rule language to eliminate the distinction between welded and 

riveted tanks. 

2-18 Comment

Clarify the intention of the term “roof covers” in section (g)(3). The term “roof covers” 

found in this section was meant to be “covers for roof fittings” according to District staff 

at the Workshop for PR 1178 on September 5, 2001. 

Response 

Staff has revised proposed rule language to incorporate this comment. 

External Floating Roof Tanks 

3-1 Comment 

There should be language included in the rule that allows the use of alternative materials 

that meet the same performance standard as the VOC impervious sock used to cover or 

plug the adjustable roof legs when the roof of the tank is floating. 

Response 

Rule language has been added to incorporate this comment. Please refer to clause 

(d)(1)(A)(iii). Gasket is allowed in place of sock. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 45 December 11, 2001 

3-2 Comment 

Under the requirements section of PR1178, it is required that the primary seal be liquid 

mounted for welded tanks and vapor mounted for riveted tanks. This is not consistent 

with the draft staff report, which identifies vapor-mounted seal only as an option for 

riveted tanks although vapor mounted seals are not allowed under Rule 463. A correction 

should be made to require mechanical shoe seals for both welded and riveted tanks which 

are required to extend into the liquid per Rule 463. 

Response 

Rule language has been modified to incorporate this comment. Please refer to clause 

(d)(1)(B)(i).

3-3 Comment 

The definition of vapor tight condition for Rule 1178 (portable hydrocarbon analyzer 

reading of 500 ppm expressed as methane above background), is more stringent when 

compared to the definition expressed in Rule 463 which requires that the limit be 1000 

ppm expressed as methane above background. 

Response 

The purpose of this proposed rule is to further reduce VOC emissions from storage tanks 

located at petroleum facilities. To only use Rule 463 requirements and standards would 

not achieve the emission reduction goals associated with the SIP Settlement Agreement 

and Control Measure FUG-05. The vapor tight definition of 500 ppm will be applicable 

to the deck fitting seals of external floating roof tanks and to the, piping, valves, vents 

and openings of fixed roof tanks. This requirement will also be applicable to pressure 

relief vents associated with these fixed roof tanks. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 46 December 11, 2001 

3-4 Comment 

Delete the references to ‘vapor tight’ and ‘visible gaps.’ As noted at paragraphs 

(d)(1)(C), (d)(2)(B), and (d)(3)(C) and (D), the vapor tight requirement is inappropriate 

for floating roof tanks. Additionally, as noted at paragraph (d)(1)(B)(iii), rim seals are 

allowed a specified amount of gap that is greater than the no visible gap definition would 

allow. These phrases should therefore be deleted so that this paragraph reads as follows: 

(3) The operator shall repair, or replace any piping, valves, vents, seals, gaskets, or roof 

covers that are found to have defects or do not meet all the requirements of this rule 

before filling or refilling the storage tank, or within 72 hours after the inspection 

whichever occurs first. 

Response 

Proposed rule language has been modified to require vapor tight condition measurements 

(as per EPA Method 21) for roof openings and rim seals for floating roof tanks. 

Operators can either measure gaps or measure for vapor tight condition for roof openings. 

The draft proposed rule language requiring no visible gaps for the primary and secondary 

on external floating roof tanks has been removed. Compliance with rim seal 

requirements shall be determined only through gap measurements, as specified in the 

proposed rule which are consistent with Rule 463. 

3-5 Comment 

Delete the requirement for a "vapor tight condition". A vapor tight condition is defined 

in paragraph (c)(38) as resulting in readings on a portable hydrocarbon analyzer of less 

than 500 parts per million (PPM), expressed as methane, above background. Testing for 

leaks with an organic vapor analyzer (OVA) or other portable hydrocarbon analyzer is 

not an appropriate monitoring method for floating roofs. This testing to determine a socalled "vapor tight condition" is appropriate for closed piping systems that route vapors 

to an emission control system, but is not a meaningful measure of whether a floating roof 

is in compliance with the specified equipment standard. There is no technical basis for 

asserting that compliance with OVA monitoring would reduce the rate of emissions past 

a floating roof and, in fact, the District does not claim any reduction in emissions 

associated with this proposed provision. Furthermore, entry onto the floating roof in 

order to perform this monitoring has significant safety concerns. 

A requirement to perform OVA monitoring of internal floating roofs would, then, divert 

resources to an activity that has no associated environmental benefit while involving 

significant costs and safety considerations. This is not an appropriate outcome, and 

therefore paragraph (d)(2)(B) should be deleted in its entirety. 

Response 

Proposed rule language has been modified to require vapor tight condition measurements 

(as per EPA Method 21) for roof openings and rim seals for internal floating roof tanks. 

Operators can either measure gaps or measure for vapor tight condition for roof openings. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 47 December 11, 2001 

Compliance with rim seal requirements shall be determined only through gap 

measurements. 

3-6 Comment 

Delete emission reduction claimed for liquid-mounted rim seals. 

Response 

Staff has amended the preliminary draft staff report to incorporate this comment. 

3-7 Comment 

Allow for mechanical shoe primary seals without vapor- or liquid-mounted distinction. 

We point out that the mechanical shoe seal is a distinct category of seal for purposes of 

both EPA rule compliance and emissions estimating regardless of where the seal fabric is 

attached [liquid mounted – in contact with the liquid; vapor mounted – upper surface of 

the roof.] In addition, under AQMD Rule 463, mechanical shoe seals are considered 

Category A type (see Attachment A). Accordingly, we have been installing this type of 

seal throughout the Carson and Wilmington plants (see Figure 1 in Attachment A). In 

fact, with an estimated 82 tanks to be impacted by this provision of the Rule alone, we 

predict the seal requirement, as worded, to be as burdensome, if not more so than 

installing domes on external floating roof tanks. Without some compromise on this issue, 

the proposed compliance dates would be impossible to satisfy and far from cost effective. 

Response 

Staff has revised proposed rule language to incorporate this comment. 

3-8 Comment

Clarify what is meant by the term “openings.” This section declares rather generically 

that openings in the roof are to be kept in a vapor tight condition. The logical question 

follows: will allowable seal gaps be considered “openings”? We would hope not because 

the 500 ppmv limit would most certainly be exceeded through allowable seal gaps. 

Furthermore, entry onto the floating roof in order to perform the monitoring has 

significant safety concerns 

Response 

Staff has revised proposed rule language to define the term roof openings. Rim seals are 

not included in the definition of roof openings. Compliance with rim seal requirements 

shall be determined only through gap measurements. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 48 December 11, 2001 

3-9 Comment

Remove performance based requirement as defined by vapor tightness. We appreciate 

the 41-item definition section. We can tell much work went into developing this list. We 

would, however, ask the District to reconsider the VAPOR TIGHT CONDITION as 

outlined in the Rule [a condition that exists when the reading on an OVA is less than 500 

ppmv, expressed as methane, above background.] We accept that it was the intention of 

the District to include this provision as a way to ease the burden of inspections (in lieu of 

seal gap measurements). However, this provision creates uncertainty concerning 

potential enforcement activity and has no associated environmental benefit. Imagine the 

burden we would face if, five years from now, we have tanks with upgraded deck fittings 

and rim seals and newly installed domes [i,e., in total compliance with all hardware 

specifications of the Rule] and yet, are still not satisfying the Vapor Tight Condition. 

What further improvements are available to us? We recommend the District include 

clear and definitive language in the Rule of options available to refineries that find 

themselves in such a predicament. 

Response 

Please refer to Response to Comment 3-5. Proposed rule language has been modified to 

require vapor tight condition measurements (as per EPA Method 21) for roof openings 

(deck fittings) for fixed roof tanks. The operators can either measure gaps or measure for 

vapor tight condition for roof openings for both domed and internal floating roof tanks. 

Compliance with rim seal requirements shall be determined only through gap 

measurements. Please note that staff has inspected from several roof openings at one 

refinery (with a quarterly inspection and maintenance program) and measured VOC 

levels at 50 PPM or less. 

3-10 Comment

Remove requirement to bolt covers on gauge float wells. We expect an enormous impact 

from the requirement to bolt covers on gauge float wells in addition to the placement of 

gaskets. The gauge float wells on our tanks do not have the side flange necessary to bolt 

the covers. We would be required to weld this flange onto the well in order to satisfy this 

Rule requirement. For safety reasons associated with welding (hot-work) we are required 

to empty the tank. Furthermore, the bolting requirement of the Rule would require us to 

hire additional operators. Our procedure would have an operator at the base of the tank 

and another on top of the tank while a third, additional operator descends onto the 

floating roof to unbolt the gauge well. Depending on the stored liquid, the third operator 

descending on the roof may require respiratory equipment. These safety concerns, the 

additional staff, and the fact that an estimated 89 tanks are to be captured by the Rule 

presents enormous concerns for us. The requirement to gasket these gauge float wells is 

consistent with 40 CFR 60, Subpart Kb. Bolting exceeds the federal requirements and is 

unattainable in the proposed compliance time frame of the Rule (July 1, 2002). 
Comments and Responses Final Staff Report 

Proposed Rule 1178 49 December 11, 2001 

Response 

Staff is reviewing this issue and will work with industry to develop appropriate rule 

language. 

3-11 Comment 

Allow 10 years to upgrade existing internal floating roofs. The performance of any work 

on an internal floating roof requires entry into the tank. For obvious safety reasons, 

modifications to internal floating roofs generally require that the tank be emptied and 

degassed. The U.S. EPA has consistently determined during its own rulemaking that the 

marginal emission reductions that result from the upgrade of existing IFRs do not warrant 

emptying and degassing the tank to achieve them. U.S. EPA regulations allow up to ten 

years

6

 for the upgrade of existing internal floating roofs, in order to allow most upgrades 

to be performed when the tank has been taken out of service for a regularly scheduled 

inspection. Revise the schedule to state that the internal floating roof shall be equipped 

as specified the next time that the tank is emptied and degassed, but in any case within 10 

years.

1

 e.g., Refinery MACT [40 CFR Part 63, Subpart CC, Section 63.640, paragraph 

(h)(4)]; the HON [40 CFR Part 63, Subpart G, Section 63.119, paragraphs (b)(3)(iv) & 

(b)(5)(viii)]. 

Response 

Staff has revised proposed rule language to extend the compliance period from July 1, 

2002 to “the next time an internal floating roof tank is scheduled for emptying and 

degassing, but no later than January 1, 2007.” Staff believes that five years is a sufficient 

amount of time to address these upgrades required for internal floating roof tanks. 

3-12 Comment

A key advantage to IFRTs is increased usable tank capacity from operating the floating 

roof at a higher level, closer to the fixed roof without interference from the secondary 

seal. However, with the secondary seal still intact, tank fill capacity is lost when the 

fixed dome is installed. Federal regulations (40 CFR 60, Subpart Kb) require only a 

single liquid-mounted primary seal or mechanical shoe for an IFRT. Therefore, we 

recommend language in the Rule that would exempt tanks from having their secondary 

seals installed if a dome installation were required. The Rule revision should also include 

language that would support the removal of the secondary seal, as an option, if a dome 

installation were required. 

Response 

 
Comments and Responses Final Staff Report 

Proposed Rule 1178 50 December 11, 2001 

All of the external floating roof tanks containing materials >3psia currently have primary 

and secondary seals. District staff view the removal of secondary seals on external 

floating roof tanks is a step back from the current level of control. Therefore, District 

staff does not agree with the comment that the rule should exempt tanks from having 

their secondary seals installed, or should include language that would support the 

removal of secondary seals if a dome installation were required. District staff has 

performed a cost effectiveness analysis for installing secondary seals on existing internal 

floating roof tanks, and because it was not cost effective, District staff did not 

recommend to upgrade the rim seal systems of internal floating roof tanks. Regarding the 

issue of loosing tank capacity by installing domed roofs, District staff understands that 

domed roofs can be installed with sidewalls so that they will not reduce tank capacity, 

and the budget prices provided by the manufacturers allow for this addition. 

3-13 Comment 

Do not specify any monitoring requirement for an IFRT that would require entry into the 

tank while it contains organic liquids. Entry onto the floating roof of an IFRT poses 

significant safety concerns related to confined space entry, and it is unnecessary for 

adequately monitoring the condition of the internal floating roof. The existing inspection 

and monitoring procedures specified in AQMD Rule 463 have been effective, and they 

should continue to be the standard for internal floating roofs (including any external 

floating roofs that have been converted to internal floating roofs by the installation of an 

aluminum dome fixed roof). WSPA strongly opposes any provision that would require 

personnel to enter an IFRT while the tank contains organic liquids. 

Response 

The proposed rule language has been revised to require visual and LEL inspections 

semiannually. In addition to these semiannual inspections, District staff recommended 

the facilities to perform a complete gap measurement of rim seal systems and deck 

fittings once every 10 years or any time the tanks are emptied and degassed. Note that 

Federal rule 40CFRPart 63 Subpart WWW and Bay Area Rule require a full inspection of 

rim seal system and deck fitting once every 10 years.

Domed External Floating Roof Tanks 

4-1 Comment 

If external domes must be installed, the peripheral, top and circulation vents must remain 

open. 

Response 

District staff agrees with the comment, and has revised the language of the proposed rule 

appropriately. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 51 December 11, 2001 

4-2 Comment 

The requirement to immediately prepare and submit a compliance plan for installing 

domes imposes an undue burden that has no environmental benefit. 

Response 

District staff agrees with the comment. Therefore, staff has replaced the requirement of 

submitting a compliance plan with a requirement of submitting a status report at each 

milestone in the compliance schedule. The status report would include status of all tanks 

subject to the domed roof requirements, and the operator would provide an estimated 

compliance date for the tanks that have not yet complied with the requirements. 

4-3 Comment 

Bay Area AQMD did not require the installation of domed roof tanks to control 

emissions. 

Response 

The 1999 Settlement Agreement required the AQMD to review the Bay Area AQMD 

storage tank rules as well as other potential control options not incorporated into the Bay 

Area rule and consider any appropriate requirements during our rule development. 

Therefore, the AQMD is not limited to the scope and requirements of the Bay Area 

AQMD rules. AQMD analysis demonstrated that the installation of domes on external 

floating roof tanks is a cost effective method to reduce VOC emissions. 

4-4 Comment 

Industry is concerned that covering their external floating roof tanks with domes will 

require a different fire suppression system than the one that they currently use for 

external floating roof tanks. This is due to the fact that they feel there is a need for a fire 

suppression system designed to work within the confines of the domed space. 

Response 

Internal Floating Roof Tanks generally have reduced fire risks when compared to 

External Floating Roof Tanks (EFRTs) and the use of fixed fire suppression systems is 

often not mandatory (Reference: Footnote 1 of Appendix H of Addendum 2 of API 650, 

Draft Release on September 2001). Information provided by a dome manufacturer also 

indicates that over 80 percent of tank fires occur on EFRTs due to the fact that the rim 

seal area and pontoons may be exposed to lightning and external fire sources such as 

nearby flares. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 52 December 11, 2001 

Despite the fact noted above, each facility will be required to meet the Fire Department 

Codes of the City in which they are located and may be required to install a fire 

suppression system. However, each facility will have to be evaluated on an individual 

basis. In addition, there are facilities to which this rule applies that do have aluminum 

domes in place with fire suppression systems. 

4-5 Comment 

Support the API Standard 650 specifying domed roof tanks to freely vent. As with 

internal floating roof tanks, the function of the “domed” roof on external floaters is not to 

act as a vapor barrier, but to block the wind. Accordingly, we strongly advocates Rule 

language that supports the API Standard 650 position specifying that such tanks freely 

vent to atmosphere for safety reasons. From our meeting with AQMD staff on 

September 20th, it was made clear to us that the API consideration is the District’s intent. 

We recommend definitive language on this issue in any future Rule revision. 

Response 

Staff has revised proposed rule language to incorporate this comment. 

4-6 Comment

According to some construction companies, domed roofs may be installed while the tank 

remains in-service. If any part of the dome installation is hot-work, the tank must be 

emptied and removed from service. The cost associated with this will add to the 

equipment cost. Therefore, a refinery strongly advocates an average cost of 

approximately $310,000 per dome. 

Response 

The equipment cost that District staff received from the manufacturers vary with tank 

size, as shown in Figure 6-1 of the Draft Staff Report. District staff has recently added 

the "loss-of-use" cost, which is about 40% of the equipment cost on top of the costs that 

the District received from the manufacturers. The total cost is about $300,000 for a 150 

ft diameter tank, $74,000 for a 50 ft diameter tank, and $1.75 million for a 260 ft 

diameter tank. Instead of using an average cost, District staff has estimated costs for each 

of the tanks that will be domed. 

4-7 Comment

A refinery has different types of domed roofs on external floating roof tanks. The 

difference is found in the peripheral venting design of the dome and often how high off 

the tank the roof stands. Since we have every intention to capture bids on any new 

construction, revised Rule language should offer guidance on design specifications. 

Response 

Design specifications for domed roof tanks are listed in API Standard 650, Appendix G. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 53 December 11, 2001 

Schedule of Installing Domed Roofs 

5-1 Comment 

Industry believes that the District did not consider the complexity of scheduling tank 

outages and securing offsite storage, which will be expected to be in high demand during 

the compliance period and therefore there is a good possibility that a disruption of 

refinery production would lead to increased fuel costs. In addition, since the District also 

failed to take logistics issues into consideration, the schedule for coming into compliance 

with Rule 1178 may be not be achievable or realistic. 

Response 

Staff is sensitive to the removal of storage capacity as a result of installing domes on 

existing external floating roof tanks and the impact it may have on the supply of gasoline 

and other fuels. As a result, in November, staff is proposeding to extend the compliance 

schedule to January 1, 2006. Facilities will now would be required to dome 25% of their 

external floating roof tanks at the end of each of the four compliance years starting from 

2002 through 2006. In addition, facilities will would have the option to accept a permit 

condition not to store liquids with true vapor pressure greater than 3 psia rather than 

complying with the doming requirement of the proposed rule. An analysis of the storage 

tank capacity indicates that over the four year period to dome these tanks, on average, 

approximately 1.13% and 1.33% of the total storage capacity could be taken out of 

service at any one time at the refineries and non-refineries (tank farms and loading racks), 

respectively. Since the requirement of doming tanks varies with each facility, staff will 

continue to work with the facilities to minimize the impact of taking these tanks out of 

service. In December, responding to the feedback received from industry, staff is now 

proposing to expand the doming period to 6 years and exclude 46 crude oil tanks from the 

doming requirements due to the poor cost effectiveness. The exclusion of the crude oil 

tanks and expansion of the doming schedule from 4 years to 6 years is expected to 

alleviate the industry's concern about the doming schedule.

5-2 Comment 

The schedule of installing dome is unattainable. Issues related to 1) inability to meet the 

deadline for state mandated RFG Phase III requirements, 2) disruption to product 

deliveries and refinery production during tank outages, 3) product compatability that may 

require tank clearing/cleaning, 4) adequate storage capacity under excessive demand 

during the compliance period have not been adequately addressed. One affected facility 

proposed a ten-year period for doming. 

Response 

District staff is sensitive to the loss of storage capacity and the potential disruption to 

deliver products to the consumer. Please refer to Comment 5-1 and note that: 
Comments and Responses Final Staff Report 

Proposed Rule 1178 54 December 11, 2001 

 The deadline for state mandated RFG Phase III requirements is January 1, 2003. The 

compliance schedule for domed roofs has been extended to January 1, 2006. With the 

revised schedule, 75% of the tanks will be domed after the RFG Phase III 

requirements are in effect. Therefore, installing domed roofs is certainly not a cause 

for inability to meet the state mandated RFG Phase III requirements. 

 District staff has done an analysis (Appendix D) to show that all of the affected 

facilities would be able to utilize more than 95% of the total tank capacity at their 

facility during the doming period. Doming therefore is not expected to cause a 

disruption to product deliveries or refinery production; and the facility is expected to 

have adequate storage capacity, even without leasing, during this doming period. 

 Domed roofs can be installed on top of an external floating roof, therefore tank 

clearing/cleaning/degassing is not a necessity. 

 In addition, there is excess tank capacity that can be and is being leased from utility 

companies and Port of Los Angeles and Long Beach. 

Acknowledging that each facility may face a unique situation, District staff is openly 

seeking and awaiting input from the facilities that may be disproportionately impacted by 

the schedule of installing domed roofs. With respect to the ten-year long compliance 

schedule, knowing the working capacity of major manufacturers who fabricate domes in 

Southern California, a ten-year period for doming 241 external floating roof tanks was 

unnecessarily long. In December, responding to the feedback received from industry, 

staff is now proposing to expand the doming period from 4 years to 6 years and exclude 

46 crude oil tanks from the doming requirements. This is expected to alleviate the 

industry's concern about the doming schedule.

5-3 Comment 

Although two fabricators of domed roofs who currently fabricate and install geodomes in 

Southern California have indicated that they believe they can provide the necessary 

manpower and materials to implement the proposed rule within the three-year time 

frame, industry does not believe the schedule is achievable and realistic. 

Response 

District staff has estimated about 241 external floating roof tanks need to be retrofitted 

with domed roofs to achieve approximately 1 tpd emission reductions. Regarding the 

capacity of fabricating and installing geodesic domes, District staff has received the same 

information from the manufacturers as the industry. One manufacturer has indicated to 

District staff that they currently fabricate and install domes at a rate of 100 domes per 

year, which means that the 241 tanks could be handled by one manufacturer in less than 

three years. However, understanding the complexity associated with the scheduling and 

tank storage capacity removal issues, District staff is proposing to extend the compliance 

schedule to four years. In addition, District staff is seeking input from all impacted 

facilities, especially from those who may be disproportional impacted regarding their 
Comments and Responses Final Staff Report 

Proposed Rule 1178 55 December 11, 2001 

schedules of installing domes. In December, responding to the feedback received from 

industry, staff is now proposing to expand the doming period to 6 years and exclude 46 

crude oil tanks from the doming requirements. This is expected to alleviate the industry's 

concern about the doming schedule.

5-4 Comment 

The industry strongly encourages the District to work with the California Energy 

Commission (CEC) to poll/survey all impacted facilities about this proposed rule. The 

CEC can help assess the potential impact of this rule on the overall petroleum supply 

picture to the District. 

Response 

District staff is working closely with the CEC to minimizing the product impact on the 

supply of petroleum products caused by removing storage tank capacity to implement this 

rule. 

5-5 Comment 

The industry anticipates that the construction of domes will take from one to three 

months per tank, depending on the tank size. All the refineries will be competing for a 

limited number of constructors that can provide domes. The industry strongly 

recommends the District bifurcate the rule and delay doming until the industry can sort 

out the implementation schedule that will not adversely impact the supply of gasoline. 

Response 

Dome manufacturers have provided the District staff with the number of construction 

days needed for each tank that would be potentially domed. The number of days vary 

depending on the tank size from District staff is working closely with the CEC to 

minimizing the products impact on the supply of petroleum products caused by removing 

storage tank capacity to implement this rule. 

Fixed Roof Tanks 

6-1 Comment 

The control efficiency of carbon adsorbers used to control emissions from fixed roof 

tanks and portable tanks is only 95 percent as opposed to 98 percent required by the rule. 

Also, since these tanks are used on an as needed basis, it is not feasible to vent them to 

anything other than carbon-type controls. 

Response 
Comments and Responses Final Staff Report 

Proposed Rule 1178 56 December 11, 2001 

The rule language has been modified to reflect that the control efficiency requirement of 

carbon adsorbers is 95 percent and that venting portable tanks to carbon adsorbers that 

meet the same efficiency is sufficient control. 

6-2 Comment 

It would be almost impossible for an oil and gas production facility with vapor recovery 

that is combined with a facility fuel gas/sales gas system, to demonstrate compliance with 

the 98% control efficiency requirement. 

Response 

The rule has been modified to include language that requires the facility operator to 

operate and maintain the tank roof, fittings, piping and valves connecting the (fixed roof) 

tank to the vapor recovery compressors in accordance with Rule 1173 and PR1178. 

6-3 Comment 

Requiring the pressure-vacuum vents on fixed roof tanks to be set within 10 percent of 

the maximum allowable working pressure of the roof is unreasonable since each tank’s 

setting is unique as specified by API 650. 

Response 

This is current requirement of Rule 463 and Bay Area Rule. 

6-4 Comment 

The industry recommended District staff to drop the 98% control efficiency required for 

fixed roof tanks vented to fuel gas system. The demand on compressors by venting to 

vapor recovery systems with a 98% control efficiency would undoubtedly exceed our 

current capacity. Any increase to compressor capacity would incur huge hardware and 

piping costs throughout the refinery, would contract permitting issues and will likely 

trigger federal regulations. This would add considerable costs not contemplated in the 

proposed Rule. 

Response 

Since the MACT standards in the Federal Regulations does not require 98% control 

efficiency for fuel gas system, District staff will not make 98% control efficiency a 

requirement for fixed roof tanks that are vented to fuel gas system. 

6-5 Comment

Converting a fixed roof tank to an internal floater would remove the tank from service for 

upwards of three months and would contract similar permitting issues and trigger federal 
Comments and Responses Final Staff Report 

Proposed Rule 1178 57 December 11, 2001 

regulations. The cost to install an internal floating roof, while typically more cost 

effective than vapor recovery systems, would exceed the cost of a typical tank 

turnaround, which are currently around $300,000. 

 Response 

District staff has added a "loss-of-use" cost approximately equal to 40% of equipment 

cost in order to determine the cost effectiveness for internal floating roof tanks. In 

addition, District staff has extended the compliance date for this control strategy to 

January 1, 2007 to allow the facilities sufficient time for scheduling should they choose 

to convert the fixed roof tanks to internal floating roof tanks. 

6-6 Comment

Rule language has pressure-vacuum vents specified to be set within 10% of the 

maximum allowable working pressure of the roof or at least 0.5 psig. The industry is 

concerned with limitations implied in referencing the 0.5 psig because the true set 

pressure will be dependent on the type of tank. To be consistent with Rule 463 and with 

further language found in the Rule [(k)(1)(D)], no minimum set pressure is mandated. 

Response

This is the current requirement in Bay Area rule. The rule language allows the industry 

to choose between a set point within 10% of the maximum allowable working pressure of 

the roof or at least 0.5 psig. 

6-7 Comment 

PR1173.1 (1178) specifies that fixed-roof tanks larger than 19,815 gallons containing 

organic liquids with a TVP greater than 0.1 psia shall be equipped with controls. These 

tanks may be equipped with an internal floating roof or may be routed to an emission 

control system, but the more cost-effective option would typically be the installation of 

an internal floating roof. While WSPA acknowledges that there are merits to the concept 

of installing internal floating roofs, this is a particularly complex item. In addition to the 

need to determine cost effectiveness as a function of the various pertinent parameters, 

there are inspection and fire safety issues involved. WSPA believes that the complexity 

of this measure cannot be adequately addressed in a simple comment letter, and thus 

WSPA suggests the discussion of these issues in more detail with staff. 

Response 

District staff will continue meeting with the industry to discuss this issue. 

6-8 Comment 
Comments and Responses Final Staff Report 

Proposed Rule 1178 58 December 11, 2001 

Where vapors from an emission point are routed to a fuel gas system, the U.S. EPA 

regards such vapors as having never left the process. The U.S. EPA typically exempts 

such emission points from the applicability of the rule, thereby avoiding the application 

of control efficiency determinations to process equipment. This same principle should be 

invoked by PR 1173.1. Stipulate that storage tanks routed to a fuel gas system are 

exempt from the requirements of this rule, for example, Refinery MACT [40 CFR Part 

63, Subpart CC, Section 63.640, paragraph (d)(5). 

Response 

The rule language has been revised to incorporate this comment. 

Operator Inspection 

7-1 Comment 

Will Method 21 certification be included as part of a revised inspector tank certification 

under Rule 463 or under the certification training required under Rule 1176? 

Response 

A completion certificate will be offered by attending CARB Fugitive Emissions Operator 

Training Course #395. The course could be synchronized with the Rule 463 certification 

class offered by AQMD. 

7-2 Comment 

Under Rule 463, entry is not required to conduct visual inspections of the tank seals and 

to take LEL readings for in-service internal floating roof tanks. Therefore, this 

requirement should be removed. 

Response 

Visual inspections and LEL readings are required to be conducted semiannually. Gap 

measurement of the rim seal system, gap measurement of the deck fittings or Method 21 

measurement are required once every ten years or whenever the tank is emptied or 

degassed. 

7-3 Comment 

Since inspections for Rule 463 and PR1178 will be conducted at the same time, can the 

written report required for tanks determined to be in violation of Rule 463, be modified 

and submitted to meet the compliance requirements of PR1178? 

Response 
Comments and Responses Final Staff Report 

Proposed Rule 1178 59 December 11, 2001 

Inspection procedures and Compliance Report Form for PR1178 have been modeled after 

Rule 463, have been developed and included as Attachment A of PR1178. 

7-4 Comment 

The rule requires that there be inspection of domed roof tanks and internal floating roof 

tanks using EPA Method 21, which requires that the probe on the hydrocarbon analyzer 

be placed within one centimeter of the fugitive source. There are safety concerns 

regarding personnel entering the confined space between the floating roof and the dome. 

It is recommended that the District not deviate from the inspection criteria specified in 

Rule 463. 

Response 

The rule has been revised to incorporate this comment. Inspection requirements for 

internal floating roof tanks and domed external floating roof tanks will be in accordance 

with the requirements specified in Rule 463. 

7-5 Comment

Provide access to an extended repair period. We raise the issue of the 72-hour provision 

to establish compliance on a needed repair. The additional hardware needed to inspect 

and, possibly repair, will likely challenge the 72-hour limit. Based on our current 

experience at satisfying the 72-hour compliance period of Rule 463, we recommend 

language that would support a repair exceeding 72 hours. For example, gaining entry 

into a confined space will result in additional time needed to affect repairs. 

Response

Staff believes that the requirement to repair within 72 hours is appropriate and consistent 

with Rule 463. Since staff has received comment on this issue from only one facility, it 

does not appear to be an industry-wide problem and may be more appropriately 

addressed on a case by case basis through the variance process. 

7-6 Comment 

Testing for leaks with an organic vapor analyzer (OVA) or other portable hydrocarbon 

analyzer is not an appropriate monitoring method for floating roof tanks. This testing to 

determine a so-called "vapor tight condition" is appropriate for closed piping systems that 

route vapors to an emission control system, but is not a meaningful measure of whether a 

floating roof tank is in compliance with the specified equipment standard, nor is it 

appropriate for fixed-roof tanks that are not routed to an emission control system. In 

order to have the requirement for vapor tight pressure-vacuum vents apply only to the 

tanks for which they are appropriate, paragraphs (d)(3)(C) and (D) should be renumbered 

as paragraphs (d)(3)(A)(iv) and (v). 
Comments and Responses Final Staff Report 

Proposed Rule 1178 60 December 11, 2001 

Response 

Some deck fittings on floating roof tanks are configured such that gap measurements are 

not feasible. In this situation, monitoring with OVA is an appropriate method to detect 

leaks. The fixed roof tanks subject to PR1178 are all routed to vapor control, therefore 

vapor-tight condition is an appropriate requirement. District staff has renumbered the 

paragraphs as suggested by the industry to eliminate confusion. 

Test Methods and Procedures 

8-1 Comment 

There should be a listing of specifically defined products that would be exempt from the 

rule including, diesel, jet fuel, gas oil, fuel oil and asphalt. 

Response 

These generalized terminologies for ranges of petroleum fractions do not necessarily 

represent the emissions characteristics for tank contents which may vary on both an inter 

and intra-refinery/facility basis. Additionally, product blendstocks and many of the 

intermediate refined streams often use these terminologies despite the fact that they are 

not, in themselves, saleable products that meet final product specifications. Furthermore, 

the terminology for the tank contents does not take into account actual storage conditions 

such as temperature. Because of this, the rule must therefore rely on a measurement that 

can act as a surrogate for potential emissions for determining applicability. True vapor 

pressure (TVP) is the criterion that the Tanks 4 software, developed by EPA and API, 

uses to determine tank content emissions characteristics. The Tanks 4 software along 

with information submitted by the affected facilities was used to perform the cost 

effectiveness analysis of the rule. Due to difficulties in measuring very low TVPs, 

ASTM Methods D-86 and D-93, for non-heated and heated tank contents respectively 

will be used to determine if a product should be exempt from the requirements of the 

rule. Furthermore, since the flash point threshold for organic liquids that are stored at 

ambient temperatures has been revised and set at 100 degree F, listing specifically 

defined products as exempt products is no longer necessary. 

8-2 Comment 

Flash point is not a proper surrogate for vapor pressure and it is recommended that either 

a single method be specified such as ASTM Method D-86 which is proposed in this rule 

or that there be a list of compounds and their specified vapor pressures as in Rule 463. 

Response 

Although flash point is not a proper surrogate for higher vapor pressures, the method for 

determining flash point is far superior to the method for determining vapor pressure in 

terms of precision and accuracy for the types of products near the proposed 0.1 psi TVP 
Comments and Responses Final Staff Report 

Proposed Rule 1178 61 December 11, 2001 

threshold for rule applicability. Both refinery and District members of the working group 

have raised the issue of the difficulty of determining low vapor pressures. To resolve this 

issue, the flash point test method was chosen as a test method that has the capability of 

discerning between product types and petroleum fractions near the 0.1 psi TVP threshold 

that was used in the cost effectiveness analysis of the rule. An addition to the precision 

and accuracy considerations, the flash point method was also considered to have 

advantages with respect to cost and ease of analysis since the analysis is considered to be 

very inexpensive and since most or all affected facilities have current capabilities to run 

the analysis in-house. 

8-3 Comment 

ASTM Method D-86 is unreliable for crude oil samples and the District should specify or 

develop an alternative method (such as District Method 304-91), which is suitable for use 

at oil and gas production facilities. The difficulty in de-watering many crude oil samples 

often leads to either aborted or compromised ASTM Method D-86 test results. 

Response 

It is understood that water will, in effect, be treated as a VOC by the ASTM D-86 

approach. The rule language as been changed so that the ASTM D-86 approach applies 

to tanks with heated contents only which are not expected to have significant water 

content. District staff is considered Proposed Rule 1178 will exempt crude oil tanks from 

the doming equirements. In essenceTherefore, ASTM Method D-86 would not be used 

for crude oils.

8-4 Comment 

The applicability criteria for materials included in this rule is based on true vapor 

pressure, which can vary with temperature. Will the true vapor pressure measurement be 

based on an annual average or on the highest vapor pressure at some maximum 

temperature? 

Response 

The advantage of the TVP approach is that it mimics actual emission characteristics in 

that both TVP and actual emissions increase as a function of temperature. Recognizing, 

however, TVP variations due to diurnal and/or seasonal variations in ambient temperature 

may create an uncertainty with respect to the number of external floating roof tanks that 

will be subject to the doming requirement of the proposed rule, staff is proposing the 

TVP to be measured at 750 degree F. 

8-5 Comment 
Comments and Responses Final Staff Report 

Proposed Rule 1178 62 December 11, 2001 

Since ASTM Method D86 is a volumetric method, the rule applicability should be based 

on a 10% volume recovered as opposed to the 10% mass recovered in the draft rule. 

Response 

The rule language has been revised to specify 10% volume recovered as opposed to the 

10% mass recovered for the ASTM method used to determine rule applicability. 

8-6 Comment 

Asphalt plants that do not produce gasoline, jet fuel or diesel and do not have any 

complicated processing units normally associated with larger refineries such as hydrotreating, coking or thermal cracking should be exempted from the rule. 

Response 

Given the variety of hydrocarbons present in crudes, even facilities that produce 

exclusively asphalts from crudes cannot be exempted specifically from the rule due to the 

potential for emissions of the light ends in the crudes. Additionally, since these asphalt 

plants typically store heated products, there is a potential to overheat the product to the 

point where the 0.1 psi TVP as determined in the rule can be exceeded. Provided, 

however, that the tank contents fall under the 0.1 psi TVP as determined by the test 

methods as applicable in the rule, specific tanks within asphalt plants can be exempt from 

the requirements of the rule. 

8-7 Comment 

Kerosene, diesel, and all heavier products should be exempt from the rule because the 

TVP is below 0.1 psi. 

Response 

The flash point applicability limit has been revised to 100 degree F. This revision will 

exempt many of the materials stored such as diesel and heavier products with TVP below 

0.1 psi. 

8-8 Comment 

ASTM 5191 as a test method for the 3 psi threshold may not be applicable to crude 

samples. 

Response 

The District welcomes suggestions for test methods for determining vapor pressures for 

the 3 psi threshold. District staff recommends ASTM Method D-2889 for true vapor 
Comments and Responses Final Staff Report 

Proposed Rule 1178 63 December 11, 2001 

pressure or ASTM Method D-323 for Reid Vapor Pressure and converted to TVP using 

AP42 or other approved nomographs. 

8-9 Comment 

The language in the test method section for multiple test methods needs to be explained. 

Response 

The language regarding multiple test methods was borrowed from Rule 1132 and would 

apply to source tests for control systems only. Each sentence was intended to remedy 

two problems that are often encountered. The cause of both of the problems is that some 

of these test methods will bias the emissions low in certain applications. The first 

sentence is designed to give the District the authority to prevent the use of a low biasing 

test method when the District evaluates source test protocols. This has proven to be 

difficult when rules specify several test methods. The second sentence is designed to 

address the problem that when a violation is detected, Notices of Violations potentially 

cannot be issued because failure by all of the test methods cited in the rule cannot be 

proven. Both sentences are therefore needed in order to make the rule enforceable. 

8-10 Comment 

The procedures for refinery laboratories to receive LAP approval and sampling 

authorization should be clarified. 

Response 

PR1178 cites both District source test methods (e.g. SCAQMD Method 25.1) for testing 

control device efficiency, and non-source test methods (e.g. EPA Method 21 and ASTM 

Method D-93) for performing inspections and determining rule applicability. PR1178 

also states that the LAP approval is required only for those methods where a LAP 

approval process exists. The LAP process primarily applies to source test methods. 

Additionally, Rule 304 states that testing shall be conducted by the District or an 

independent laboratory. This is interpreted to apply to the source test methods. For the 

non-source test methods, the testing may be conducted by the refinery and reported as 

under reporting and recordkeeping requirements. Currently, since there is no existing 

LAP process for the non-source test methods, the refineries may conduct this testing 

without LAP approval. It should be noted, however, that the District also has the option 

to perform testing and issue notices of violations based on its test results. 

8-11 Comment 

Must the tank content sampling comply with ASTM D-4057, Manual Sampling of 

Petroleum and Petroleum Products. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 64 December 11, 2001 

Response 

The samples must be obtained in a manner which is representative of the tank contents as 

with respect to the intention of the rule. ASTM Method D-4057 will generally apply as 

the standard for sampling petroleum products and is cited in many other ASTM methods 

of analysis. 

8-12 Comment 

District should explicitly exempt asphalt and asphalt like material from the rule since 

cracking may occur during the ASTM Method D-86 analysis causing a bias in the test 

results. 

Response 

ASTM Method D-86 states that the distillation is deemed as completed once sample 

decomposition is encountered. The remaining non-distilled portion of the sample is 

considered as residual and not counted in the 10% recovery as specified in PR1178. The 

effect of cracking of the samples at high temperatures is, therefore, not considered to bias 

the test results which are based on the volume recovered. 

8-13 Comment

Use a true vapor pressure test method for 3 psia threshold. The proposed Rule, as 

written, is unclear which test method should be used to verify the 3 psia threshold for 

dome installations. A more traditional vapor pressure test method could be applied and 

We recommend ASTM D-5191 [good for determining vapor pressures from 1 to 18 psia] 

or ASTM D-323. 

Response 

Staff has reviewed this issue and revised proposed rule language that states that ASTM 

Method D-2889 should be used to determine true vapor pressure, and ASTM Method D323 should be used to determine Reid vapor pressure and AP-42 or District approved 

nomographs to convert to true vapor pressure. 

Exemption 

9-1 Comment 

Since pressure vessels have pressure relief devices (PRDs) that vent to the atmosphere 

under very high-pressure scenarios, exemptions for these vessels should specify a range 

of operation for PRDs. 

Response 
Comments and Responses Final Staff Report 

Proposed Rule 1178 65 December 11, 2001 

This section of the rule has been modified to incorporate the comment. 

9-2 Comment 

Exempt tank sampling systems for vapor tightness. We have several sampling systems 

along various tank shells that could become a challenge to keep in a vapor tight condition 

as defined in the Rule. We solicit language from the District that would exempt such 

systems because they are not actually part of the tank or tank shell. 

Response 

Vapor tight conditions are applicable only to roof openings and as a monitoring option 

for rim seals. The definition for roof openings does not include tank sampling systems. 

Therefore, tank sampling systems are exempt by definition. 

9-3 Comment 

Exempt liquids not containing a majority of Volatile Organic Compounds. We have 

encountered situations where the vapor pressure from the top layer of a liquid [e.g., oil on 

water] triggers Rule 463 even though a representative sample of the liquid clearly is not 

VOC containing material. For example, we include storm/waste water tanks in our Rule 

463 program due to the potential for this oily film to develop on top of the liquid which 

may have a high enough vapor pressure. We request the District to offer guidance 

through Rule language on how to deal with this type of situation. 

Response

Staff is reviewing this issue and will work with industry to develop appropriate rule 

language. 

Emission Reductions and Cost Effectiveness Analysis

10-1 Comment 

If this rule includes portable tanks that are stationary, their emissions and cost impact 

should be included in the draft staff report. 

Response 

Permits for portable storage tanks storing liquids with high vapor pressure materials 

require venting to carbon canisters. Therefore, this type of storage tanks should comply 

with the requirements of fixed roof storage tanks under paragraph (d)(4). Furthermore, 

since most of these tanks are already permitting with carbon adsorbers, no additional 

costs are anticipated. Furthermore, costs for retrofitting with carbon canisters are 

expected to be significantly lower than costs for retrofitting with internal floating roofs to 
Comments and Responses Final Staff Report 

Proposed Rule 1178 66 December 11, 2001 

achieve same amount of emission reductions. Therefore, the cost effectiveness factor for 

tanks with carbon canister is expected to be smaller than the cost effectiveness factor 

derived for internal floating roof tanks. 

10-2 Comment 

The requirement of installing dome roofs would impose burden on sources that are 

already subject to highly effective controls. The external floating roof tanks that would 

be affected by this provision would have already achieved control efficiencies greater 

than 95% before the installation of a fixed roof. 

Response 

Additional control of VOC emissions is technically and economically feasible and 

needed to achieve state and federal air quality standards for Ozone and PM. District staff 

has estimated that installing domed roofs would reduce deck fitting losses by 47%, rim 

seal losses by 79%, and VOC emissions by 0.95 tpd after full implementation. After 

excluding the emission reductions from crude oil tanks, the total emission reductions 

would be about 0.89 tpd. 

10-3 Comment 

District staff has overestimated and double counted incremental emission reductions for 

domes. 

Response 

Since the external floating roof tanks containing materials with TVP >3 psia currently are 

equipped with mechanical shoe primary seals and rim-mounted secondary, there is no 

emission reductions associated with upgrading rim seal systems for domed tanks. The 

emission reductions associated with upgrading deck fittings for external floating roof 

tanks are small, approximately 25.31 tpy for all 526 external floating roof tanks. 

Nevertheless, to be conservative in the incremental cost effectiveness estimation for 

domed roofs, District staff has deducted the whole 25.31 tpy from the 373.59 tpy 

emission reductions for domed roofs to obtain the incremental emission reductions of 

348.27 tpy (0.95 tpd) for domed roofs. Please refer to Appendix B of Draft Staff Report 

for further information. After excluding the emission reductions from crude oil tanks, the 

total emission reductions would be about 0.89 tpd.

10-4 Comment 

The requirement of dome roofs would impose enormous capital expenditures for a small 

potential emissions benefit, resulting in an estimated cost effectiveness factor of 

approximately $30,000 per ton VOC reduced. This cost effectiveness factor was based 

on a preliminary analysis of 195 external floating roof tanks potentially subject to the 

domed roof requirements at six affected refineries in the basin. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 67 December 11, 2001 

Response 

The cost effectiveness analysis used to estimate the $30,000 per ton VOC reduced was 

not based on a Discounted Cash Flow (DCF) Method, which is the methodology that 

District staff would use to determine cost effectiveness factor for a proposed rule and 

AQMP since 1995. In addition, the number of 195 external floating roof tanks may 

include tanks containing organic liquids with true vapor pressures (TVP) lower than 3 

psia at average storage temperatures. These tanks would provide smaller amount of 

emission reductions at the same cost of installing domes compared to the tanks 

containing materials at higher TVPs. The high cost effectiveness factors for tanks 

containing low TVP materials push the overall cost effectiveness factor upward. Using 

the DCF approach and the emission inventory provided by the refineries, District staff 

estimated about 137 external floating roof tanks that would be affected at six refineries, 

and estimated a cost effectiveness of about $12,000 per ton VOC reduced. Further 

excluding crude oil tanks from doming would bring the overall cost effectiveness factor 

down to approximately $9,583 per ton VOC reduced.

10-5 Comment 

Recommend the District to follow a well defined method of segregating each control 

technology and evaluate the cost effectiveness based on its own merits. 

Response 

The cost effectiveness of each control measure as well as the cost effectiveness of the 

entire Proposed Rule 1178 were presented in Table 6-6 of the Preliminary Draft Staff 

Report. 

10-6 Comment 

One refinery estimated emission reductions of 33.56 tpy for doming 30 tanks at a cost 

effectiveness factor of $33,650 per ton. To derive this cost effectiveness factor, the 

refinery included labor costs for its own refinery, contingency, and leased storage 

expenditures on top of the vendor quotes for domes. This refinery then compared 

$33,650 per ton with a cost effectiveness factor of $13,500 per ton for District 

Architectural Coatings Rule 1113, and a cost effectiveness factor of $19,00 per ton for 

BACT to conclude that domed roofs would not be a cost effective control measure. 

Response 

Even though this refinery seemed to estimate correct emission reductions for doming 30 

tanks using EPA TANK 4.0 program, this refinery had used a different methodology than 

the Discounted Cash Flow (DCF) Method that District staff would use to estimate a cost 

effectiveness factor for a control measure since 1995. It is therefore inaccurate and 

misleading to compare the cost effectiveness factor of $33,650 per ton derived by this 

refinery with the cost effectiveness factors of $13,500 per ton for Rule 1113, and $19,000 
Comments and Responses Final Staff Report 

Proposed Rule 1178 68 December 11, 2001 

per ton for BACT derived following the DCF methodology. In addition, incorporating 

additional contingency and in-house labor costs, which could vary significantly between 

the refineries, may be warranted for budgeting purposes but are inappropriate for cost 

effectiveness calculations. Staff's analysis and quotes received from vendors already 

account for such contingencies. Additional contingencies would bias the cost 

effectiveness factor unnecessarily high. Furthermore, District staff has factored in a 

“loss-of-use” cost which was estimated based on a leasing cost for temporary storage at 

all affected facilities regardless of the fact that some facilities may not actually have to 

lease temporary storage, and re-estimated the cost effectiveness for domes to arrive at a 

cost effectiveness factor of $12,103 per ton using the DCF methodology. At $12,103 per 

ton, doming is a cost effective control measure. Further excluding crude oil tanks from 

doming would bring the overall cost effectiveness factor down to approximately $9,583 

per ton VOC reduced.

10-7 Comment 

Recommend the District to 1) follow a cost effective methodology adopted by U.S. EPA 

Office of Air Quality Planning and Standards (OAQPS), and 2) use an interest rate of 7% 

to determine cost effectiveness factor. 

Response 

District staff acknowledges the recommendation. Cost effectiveness analysis is a tool to 

generate a cost effectiveness factor for a control measure. By comparing the cost 

effectiveness factors of several control measures with each others, one can acquire 

knowledge about the costs of each control measure relating to their effectiveness in 

controlling a particular pollutant. It is necessary to compare cost effectiveness factors of 

different control measures derived using the same methodology and the same 

assumptions. District staff has been using Discounted Cash Flow Method with a 4% real 

interest rate to determine cost effectiveness factor for numerous proposed rules since 

1995. 

10-8 Comment 

Because of the disproportionate hardship to small refiners, a separate cost effectiveness 

analysis addressing the unique situation of small refiners is necessary. Small refiners 

should be provided additional time to comply with the rule requirements. 

Response 

A small refiner could potentially be a major source of pollution. The cost of control 

measures and the cost effectiveness analysis are neutral with respect to the size of 

facilities impacted and, therefore, separate cost-effectiveness analysis is not warranted 

more appropriate. However, the District will conduct a thorough socioeconomic analysis 

to more accurately quantify the cost impacts on various segments of the local economy. 
Comments and Responses Final Staff Report 

Proposed Rule 1178 69 December 11, 2001 

With respect to the compliance schedule, District staff's goal is to arrive at a compliance 

schedule that is fair and equitable to all impacted facilities, small or large. 

10-9 Comment 

District has grossly underestimated the cost of converting fixed roof tanks to internal 

floating roof tanks or venting them to vapor recovery. The costs for venting vapors from 

storage tanks to vapor recovery are extremely high.

Response 

There are two options to further control emissions from fixed roof tanks containing 

liquids with true vapor pressures between 0.5 psia and 0.1 psia, either the emissions 

would be vented to vapor recovery, or the fixed roof tanks would be converted to internal 

floating roof tanks. The costs associated with venting the emissions to vapor recovery 

would vary significantly from scenarios to scenarios. To obtain one representative cost 

effectiveness factor for this control option, District staff has estimated cost effectiveness 

factor for internal floating roof tanks. The cost effectiveness in the Preliminary Draft 

Staff Report has been revised to include costs associated with "loss-of-use" with the 

understanding that the tanks could not be used during the installation of the internal 

floating roofs. District staff is in the process of verifying the costs with manufacturers, 

and will update the cost effectiveness factor if necessary 
Appendix A Final Staff Report 

Proposed Rule 1178 A-1 December 11, 2001

Appendix A - List of Affected Facilities

Table A-1 - List of Affected Facilities

Type SIC Fac ID Name City 

Refinery 2911 800012 BP Arco Carson 

Refinery 2911 800030 Chevron Products Co. El Segundo 

Refinery 2911 800370 Equilon Enterprises, LLC Wilmington 

Refinery 2911 800089 Exxon Mobil Torrance 

Refinery 2911 800362 Tosco Refining Co., Carson Carson 

Refinery 2911 800363 Tosco Refining Co., Wilmington Wilmington 

Refinery 2911 800026 Ultramar Wilmington 

Refinery 2911 800264 Edgington Oil Long Beach 

Refinery 2911 800373 Cenco Santa Fe Springs

Refinery 2911 800183 Paramount Petroleum Corp. Paramount 

Refinery 2911 800393 Valero Wilmington Asphalt Plt. Wilmington 

Non-refinery 4226 65381 SFPP, LLP., Unit No. 01 Carson 

Non-refinery 4226 65382 SFPP, LLP.'s Colton Terminal Bloomington

Non-refinery 4613 111814 Tosco Refining Co/Torrance Tank Farm Torrance 

Non-refinery 5171 117560 Equilon Enterprises, LLC--Mormon Island Wilmington 

Non-refinery 5171 800015 BP Arco Vinvale Terminal South Gate 

Non-refinery 4226 800057 Kinder Morgan (GATX) Carson 

Non-refinery 5171 800198 Ultramar Inc. Wilmington 

Non-refinery 5171 800286 BP Arco Hathaway Signal Hill Signal Hill 

Non-refinery 5171 800365 Tosco Refining Co./LA Terminal, East Los Angeles 

Non-refinery 5171 800372 Equilon Enterprises, LLC Carson 

Non-refinery 5171 800052 BP Arco Terminal Serv., Four Corners Long Beach 

Non-refinery 5171 800051 BP Arco E. Hynes, Four Corners Long Beach 

Non-refinery 1311 104012 AERA Energy Hunt. Beach

Non-refinery 1311 104015 AERA Energy Yorba Linda 

Non-refinery 1311 104017 AERA Energy Hunt. Beach 

Non-refinery 1311 119907 Berry Petroleum Co. Santa Clarita 

Non-refinery 5171 800022 CalNev Bloomington 

Non-refinery 5171 800272 Chemoil Terminals Corp. Carson 

Non-refinery 5171 116931 Equilon Signal Hill Signal Hill

Non-refinery 1311 87806 Global Oil Co. Wilmington 

Non-refinery 1311 100844 Medallion California Properties Newhall

Non-refinery 5171 800079 Petro Diamond Long Beach 

Non-refinery 1311 93073 Saba Petroleum Placentia 

Non-refinery 1311 83753 Stocker Resources Inc. L.A. 

Non-refinery 1311 101977 Signal Hill Petroleum Long Beach 

Non-refinery 1311 83509 The Termo Co. Castaic

Non-refinery 1311 116488 Texaco Exploration and Production Co. S. Fe Springs 

Non-refinery 1311 800325 Tidelands Oil Production Co. Long Beach

Non-refinery 1311 68112 Tidelands Oil Production Co. Long Beach 

Non-refinery 1311 109018 Torch Operating Co. Brea 

Non-refinery 5171 800364 Tosco Colton Terminal Bloomington

Non refinery 1311 800330 Thums Long Beach Co. Long Beach

Non refinery 1311 49863 Texaco Exploration and Production Seal Beach

Non-refinery 4226 110924 Westway Terminal Co. San Pedro 
Appendix A Final Staff Report 

Proposed Rule 1178 A-2 December 11, 2001

Table A-2 - Tank Emissions by SIC Code

SIC # Facilities Tank Emissions (tpy) % of Total

2911 11 614.41 50.58

1311 14 37.58 3.09

4226 4 179.45 14.77

4613 1 45.52 3.75

5171 11 337.77 27.81

Total 41 1214.73 100
Appendix B Final Staff Report 

Proposed Rule1178 B-1 December 11, 2001 

Appendix B - Emission Reductions 

Section B-1: Estimates of Emission Reductions for Upgrading Rim 

Seals 

Table B-1 – Emission Reduction Estimates for Upgrading Rim Seal Systems of All External 

Floating Roof Tanks at Petroleum Refineries - Scenario 2 in Table 6-6 

Refinery No of 

Tank 

Tank 

Shell 

Primary Seal Secondary Seal Rim Loss Initial 

(E rimseal) 

(tpy) 

Percent 

Reduction 

(PR rimseal)

(%) 

Reduction

(ER rimseal) 

(tpy) 

1 2 Riveted Mechanical Shoe None 0.08 78.09 0.06

1 13 Riveted Mechanical Shoe Rim-mounted 17.79 0.00 0.00

1 5 Welded Mechanical Shoe None 1.38 85.00 1.17

1 30 Welded Mechanical Shoe Rim-mounted 19.40 0.00 0.00

2 1 Riveted Mechanical Shoe None 1.77 85.00 1.51

2 6 Riveted Mechanical Shoe Rim-mounted 4.54 0.00 0.00

2 79 Welded Mechanical Shoe Rim-mounted 48.31 0.00 0.00

3 1 Riveted Mechanical Shoe None 0.07 78.09 0.05

3 1 Welded Liquid-mounted Rim-mounted 0.72 0.00 0.00

3 11 Welded Mechanical Shoe Rim-mounted 12.57 0.00 0.00

4 17 Riveted Mechanical Shoe Rim-mounted 22.33 0.00 0.00

4 7 Welded Liquid-mounted None 0.03 51.00 0.02

4 4 Welded Liquid-mounted Rim-mounted 0.22 0.00 0.00

4 9 Welded Mechanical Shoe None 0.18 85.00 0.15

4 29 Welded Mechanical Shoe Rim-mounted 24.84 0.00 0.00

5 10 Riveted Mechanical Shoe Rim-mounted 11.96 0.00 0.00

5 4 Welded Liquid-mounted Rim-mounted 1.27 0.00 0.00

5 15 Welded Mechanical Shoe Rim-mounted 4.64 0.00 0.00

6 6 Riveted Mechanical Shoe None 0.04 78.09 0.03

6 14 Riveted Mechanical Shoe Rim-mounted 1.81 0.00 0.00

6 1 Welded Liquid-mounted None 0.17 51.00 0.09

6 2 Welded Liquid-mounted Rim-mounted 0.29 0.00 0.00

6 26 Welded Mechanical Shoe None 5.07 85.00 4.31

6 39 Welded Mechanical Shoe Rim-mounted 12.45 0.00 0.00

6 3 Welded Mechanical Shoe Shoe-mounted 0.05 57.00 0.03

7 21 Welded Liquid-mounted Rim-mounted 3.89 0.00 0.00

7 6 Welded Mechanical Shoe Rim-mounted 5.81 0.00 0.00

Total 383 Total (tpy) 7.42 

 Total (tpd), 

ER rimseal 

0.02

Note: For each type of rim seal type i, ER rimseal, i = E rimseal, i * PR rimseal, i. For example, 0.06 tpy = 0.08 

tpy * 0.78 for riveted tanks with mechanical shoe primary seal. 
Appendix B Final Staff Report 

Proposed Rule1178 B-2 December 11, 2001 

Table B-2 – Emission Reduction Estimates for Upgrading Rim Seal Systems of 

External Floating Roof Tanks Containing Materials >0.1 psia at Petroleum Refineries 

- Scenario 1 in Table 6-6 

Refinery No of Tank Tank 

Shell 

Primary Seal Secondary 

Seal

Rim Loss Initial 

(E rimseal) 

(tpy)

Percent 

Reduction 

(PR rimseal) 

(%)

Reduction

(ER rimseal) 

(tpy)

1 11 Riveted Mechanical Shoe Rim-mounted 17.79 0.00 0.00

1 5 Welded Mechanical Shoe None 1.38 85.00 1.17

1 28 Welded Mechanical Shoe Rim-mounted 19.40 0.00 0.00

2 1 Riveted Mechanical Shoe None 1.77 78.09 1.38

2 6 Riveted Mechanical Shoe Rim-mounted 4.54 0.00 0.00

2 79 Welded Mechanical Shoe Rim-mounted 48.31 0.00 0.00

3 1 Welded Liquid-mounted Rim-mounted 0.72 0.00 0.00

3 11 Welded Mechanical Shoe Rim-mounted 12.57 0.00 0.00

4 15 Riveted Mechanical Shoe Rim-mounted 22.32 0.00 0.00

4 2 Welded Liquid-mounted Rim-mounted 0.22 0.00 0.00

4 20 Welded Mechanical Shoe Rim-mounted 24.82 0.00 0.00

5 10 Riveted Mechanical Shoe Rim-mounted 11.96 0.00 0.00

5 4 Welded Liquid-mounted Rim-mounted 1.27 0.00 0.00

5 14 Welded Mechanical Shoe Rim-mounted 4.64 0.00 0.00

6 0 Riveted Mechanical Shoe None 0.00 78.09 0.00

6 14 Riveted Mechanical Shoe Rim-mounted 1.81 0.00 0.00

6 0 Welded Liquid-mounted None 0.00 51.00 0.00

6 2 Welded Liquid-mounted Rim-mounted 0.29 0.00 0.00

6 0 Welded Mechanical Shoe None 0.00 85.00 0.00

6 39 Welded Mechanical Shoe Rim-mounted 12.45 0.00 0.00

6 0 Welded Mechanical Shoe Shoe-mounted 0.00 57.00 0.00

7 12 Welded Liquid-mounted Rim-mounted 3.85 0.00 0.00

7 5 Welded Mechanical Shoe Rim-mounted 5.80 0.00 0.00

TOTAL 279.00 TOTAL (tpy) 195.92 2.55 

TOTAL (tpd) 0.01 

Note: For each type of rim seal type i, ER rimseal, i = E rimseal, i * PR rimseal, i. For example, 1.17 tpy = 

1.38 tpy * 0.85 for welded tanks with only mechanical shoe primary seal. 

Estimate of Emission Reductions From Upgrading Rim Seals of External 

Floating Roof Tanks for Table 5-1 and Scenario 1Staff Proposal (Scenario 1) in 

Table 6-6

From Table B-2, emission reduction at 7 petroleum refineries = 2.55 tpy 

From Table 2-4, 2-5, and 2-6: 

Emissions from EFRTs at 7 petroleum refineries = 451.19 tpy 

Emissions from EFRTs at non petroleum refineries = 218.32 + 40.19 = 258.51 tpy 

Emission reduction at non-petroleum refineries = 2.55 x (258.51/451.19)= 1.46 

tpy 

Total emission reduction from rim seals = 2.55 + 1.46 = 4.01 tpy = 0.01 tpd 
Appendix B Final Staff Report 

Proposed Rule1178 B-3 December 11, 2001 

Estimate of Emission Reductions From Upgrading Rim Seals of External 

Floating Roof Tanks for Scenario 2 in Table 6-6

From Table B-1, emission reduction at 7 petroleum refineries = 7.42 tpy for 

approximately 61 external floating roof tanks 

From Table 2-4, 2-5, and 2-6: 

Emissions from EFRTs at 7 petroleum refineries = 451.19 tpy 

Emissions from EFRTs at non petroleum refineries = 218.32 + 40.19 = 258.51 tpy 

Emission reduction at non-petroleum refineries = 7.42 x (258.51/451.19) = 4.25 

tpy for approximately (61 x ((99+234)/308)) = 66 tanks 

Total emission reduction from rim seals = 7.42 + 4.25 = 11.67 tpy = 0.03 tpd for 

approximately (61 + 66 = 127) tanks 

Estimate of Emission Reductions From Upgrading Rim Seals of Internal 

Floating Roof Tanks for Scenario 2 in Table 6-6

Emission reduction for 35 internal floating roof tanks at petroleum refineries = 1 tpy 

From Table 2-4, 2-5, and 2-6: 

Emissions from IFRTs at petroleum refineries = 20.72 tpy 

Emissions from IFRTs at non petroleum refineries = 237.78 + 34.49 = 272.27 tpy 

Emission reduction at non-petroleum refineries = 1 x (272.27/20.72) = 13.14 tpy 

for approximately 163 tanks 

Total emission reduction from rim seals = 1 + 13.14 = 14.14 tpy = 0.04 tpd for 

approximately (35 + 163 = 198) tanks 
Appendix B Final Staff Report 

Proposed Rule1178 B-4 December 11, 2001 

Section B-2: Estimates of Emission Reductions for Upgrading Deck 

Fittings

Table B-3 – Average Percent Reduction for External Floating Roof Tanks 

Deck Fitting Type Deck Covering Type Total 

Quantity 

(N) 

PercentageR

eduction 

(PR deck 

fitting,j) 

Average 

percentage 

reduction for 

deck fitting 

type j 

Access Hatch (24-in. Diam.) Bolted Cover, Gasketed 459 0.00 0.00

Access Hatch (24-in. Diam.) Unbolted Cover, Gasketed 1 97.62 0.01

Access Hatch (24-in. Diam.) Unbolted Cover, Ungasketed 42 97.76 0.26

Automatic Gauge Float Well Bolted Cover, Gasketed 33 0.00 0.00

Automatic Gauge Float Well Unbolted Cover, Gasketed 29 91.83 0.17

Automatic Gauge Float Well Unbolted Cover, Ungasketed 222 93.32 1.33

Column Well (24-in. Diam.) Pipe Col.-Sliding Cover, Gask. 1 60.00 0.00

Gauge-Hatch/Sample Well (8-in. Diam.) Weighted Mech. Actuation, Gask. 357 0.00 0.00

Gauge-Hatch/Sample Well (8-in. Diam.) Weighted Mech. Actuation, Ungask. 46 75.86 0.22

Rim Vent (6-in. Diameter) Weighted Mech. Actuation, Gask. 136 0.00 0.00

Rim Vent (6-in. Diameter) Weighted Mech. Actuation, Ungask. 23 86.71 0.13

Roof Drain (3-in. Diameter) 90% Closed 266 0.00 0.00

Roof Drain (3-in. Diameter) Open 38 39.31 0.11

Roof Leg (3-in. Diameter) Adjustable, Center Area, Gasketed 3322 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Center Area, Sock 2,382 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Center Area, Ungasketed 687 54.96 2.40

Roof Leg (3-in. Diameter) Adjustable, Double-Deck Roofs 1560 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Pontoon Area, Gasketed 2838 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Pontoon Area, Sock 1,512 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Pontoon Area, Ungasketed 446 56.07 1.59

Roof Leg (3-in. Diameter) Fixed 257 0.00 0.00

Roof Leg or Hanger Well Adjustable 117 100.00 0.74

Sample Pipe or Well (24-in. Diam.) Slit Fabric Seal 10% Open 73 0.00 0.00

Slotted Guide-Pole/Sample Well Gask Sliding Covr, w. Float,Sleeve,Wiper 50 0.00 0.00

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Float 3 93.50 0.02

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Float, Wiper 17 64.70 0.07

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Pole Sleeve 3 87.37 0.02

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Pole Wiper 25 88.73 0.14

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w/o Float 3 97.83 0.02

Stub Drain (1-in Diameter) 52 0.00 0.00

Unslotted Guide-Pole Well Gasketed Sliding Cover 12 93.05 0.07

Unslotted Guide-Pole Well Gasketed Sliding Cover, w. Sleeve 52 0.00 0.17

Unslotted Guide-Pole Well Gasketed sliding Cover, w. Wiper 111 0.00 0.00

Unslotted Guide-Pole Well Ungasketed Sliding Cover 19 97.92 0.12

Unslotted Guide-Pole Well Ungasketed Sliding Cover, w. Sleeve 2 65.80 0.01

Vacuum Breaker (10-in. Diam.) Weighted Mech. Actuation, Gask. 329 0.00 0.00

Vacuum Breaker (10-in. Diam.) Weighted Mech. Actuation, Ungask. 56 5.47 0.02

TOTAL 15,581 APR = 7.49 
Appendix B Final Staff Report 

Proposed Rule1178 B-5 December 11, 2001 

Table B-4 – Average Percent Reduction for Internal Floating Roof Tanks 

Deck Fitting Type Deck Covering Type Total 

Quantity 

(N) 

Percentage

Reduction

(PR deck 

fitting,j) 

Average 

percentage 

reduction 

for deck 

fitting type j 

Access Hatch (24-in. Diam.) Bolted Cover, Gasketed 27 0.00 0.00

Access Hatch (24-in. Diam.) Unbolted cover, Gasketed 2 94.84 0.19

Access Hatch (24-in. Diam.) Unbolted Cover, Ungasketed 27 95.56 2.61

Automatic Gauge Float Well Bolted Cover, Gasketed 4 0.00 0.00

Automatic Gauge Float Well Unbolted Cover, Gasketed 2 34.88 0.07

Automatic Gauge Float Well Unbolted Cover, Ungasketed 22 80.00 1.78

Column Well (24-in. Diam.) Built-Up Col.-Sliding Cover, Ungask. 84 78.72 6.69

Column Well (24-in. Diam.) Pipe Col.-Sliding Cover, Gask. 10 60.00 0.61

Gauge-Hatch/Sample Well (8-in. Diam.) Weighted Mech. Actuation, Gask. 26 0.00 0.00

Gauge-Hatch/Sample Well (8-in. Diam.) Weighted Mech. Actuation, Ungask. 3 79.58 0.24

Ladder Well (36-in. Diam.) Sliding Cover, Gasketed 1 0.00 0.00

Ladder Well (36-in. Diam.) Sliding Cover, Ungasketed 21 26.32 0.56

Roof Leg or Hanger Well Adjustable 541 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Center Area, Gasketed 8 0.00 0.00

Roof Leg (3-in. Diameter) Adjustable, Pontoon Area, Gasketed 7 7.64 0.05

Roof Leg (3-in. Diameter) Adjustable, Pontoon Area, Ungasketed 130 39.95 5.25

Sample Pipe or Well (24-in. Diam.) Slit Fabric Seal 10% Open 21 0.00 0.00

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Float 2 93.50 0.19

Slotted Guide-Pole/Sample Well Gask. Sliding Cover, w. Float, Wiper 1 64.70 0.07

Stub Drain (1-in Diameter) 4 0.00 0.00

Unslotted Guide-Pole Well Gasketed Sliding Cover 6 65.60 0.40

Unslotted Guide-Pole Well Gasketed sliding Cover, w. Wiper 1 0.00 0.00

Vacuum Breaker (10-in. Diam.) Weighted Mech. Actuation, Gask. 28 0.00 0.00

Vacuum Breaker (10-in. Diam.) Weighted Mech. Actuation, Ungask. 11 20.51 0.23

TOTAL 989 APR = 18.93
Appendix B Final Staff Report 

Proposed Rule1178 B-6 December 11, 2001 

Table B-5 – Emission Reduction Estimates for Upgrading Deck Fittings 

Refinery No of 

Tank 

Tank Type Deck Fitting 

Loss (tpy) 

Deck Seam 

Loss (tpy) 

 

1 2 External Floating Roof Tank 0.0026755

1 13 External Floating Roof Tank 3.4874672

1 5 External Floating Roof Tank 0.1364386

1 30 External Floating Roof Tank 8.2205859

2 1 External Floating Roof Tank 1.6102257

2 8 External Floating Roof Tank 4.3981815

2 6 External Floating Roof Tank 1.8265909

2 96 External Floating Roof Tank 90.232071

2 1 External Floating Roof Tank 0.0446179

3 1 External Floating Roof Tank 0.0294418

3 1 External Floating Roof Tank 6.2114569

3 11 External Floating Roof Tank 45.237567

4 17 External Floating Roof Tank 13.015572

4 7 External Floating Roof Tank 0.0263542

4 4 External Floating Roof Tank 0.8067324

4 9 External Floating Roof Tank 0.0369583

4 29 External Floating Roof Tank 21.410112

5 10 External Floating Roof Tank 2.4841894

5 4 External Floating Roof Tank 1.1072569

5 15 External Floating Roof Tank 1.8550396

6 6 External Floating Roof Tank 0.0022938

6 14 External Floating Roof Tank 0.8029719

6 1 External Floating Roof Tank 0.0550625

6 2 External Floating Roof Tank 0.2703203

6 26 External Floating Roof Tank 0.3850399

6 39 External Floating Roof Tank 5.256555

6 3 External Floating Roof Tank 0.0078232

7 21 External Floating Roof Tank 3.764789

7 6 External Floating Roof Tank 2.0835597

Total 388 214.81 Average 

Percentage 

Reduction = 

7.49 

Fitting Losses 

= 16.09 tpy 

(0.05 tpd) 

1 1 Internal Floating Roof Tank 8.2548613

1 3 Internal Floating Roof Tank 1.0202083

2 4 Internal Floating Roof Tank 0.1080575 0.23

2 3 Internal Floating Roof Tank 0.339611 0.29

2 3 Internal Floating Roof Tank 0.52812 0.05

2 3 Internal Floating Roof Tank 0.1614993 0.08

8 14 Internal Floating Roof Tank 2.2675

3 1 Internal Floating Roof Tank 0.6639829 0.05

4 1 Internal Floating Roof Tank 0.9563761

5 2 Internal Floating Roof Tank 0.0981258

Total 35 14.40 0.7 Average 

Percentage

Reduction = 

18.93 

Fitting Losses 

= 2.86 tpy (0.01 

tpd) 
Appendix B Final Staff Report 

Proposed Rule1178 B-7 December 11, 2001 

Estimate of Emission Reductions from Upgrading Deck Fittings in Table 5-1 

and Both Scenarios 1 and 2 in Table 6-6 

• From Table B-5, emission reduction for EFRTs at 7 petroleum refineries = 16.09 tpy

From Table 2-4, 2-5, and 2-6: 

Emissions from EFRTs at 7 petroleum refineries = 451.19 tpy 

Emissions from EFRTs at non petroleum refineries = 218.32 + 40.19 = 258.51 tpy 

Emission reduction at non-petroleum refineries = 16.09 x (258.51/451.19) = 9.22 tpy 

Total emission reduction from deck fittings on EFRTs = 16.09 + 9.22 = 25.31 tpy

• From Table B-5, emission reduction for IFRTs at 7 petroleum refineries = 2.86 tpy

From Table 2-4, 2-5, and 2-6: 

Emissions from IFRTs at 7 petroleum refineries = 20.72 tpy 

Emissions from IFRTs at non petroleum refineries = 237.78 + 34.49 = 272.27 tpy 

Emission reduction at non-petroleum refineries = 2.86 x (272.27/20.72) = 37.58 tpy 

Total emission reduction from deck fittings on IFRTs = 2.86 + 37.58 = 40.44 tpy 

• Total emission from deck fittings on all floating roof tanks at petroleum refineries = 16.09 + 

2.86 = 18.95 tpy or 0.05 tpd 

Total emission reduction from deck fittings on all floating roof tanks at non petroleum 

facilities = 9.22 + 37.58 = 46.80 tpy or 0.13 tpd 

Total emission reduction from deck fittings = 18.95 + 46.80 = 65.75 tpy or 0.18 tpd 
Appendix B Final Staff Report 

Proposed Rule1178 B-8 December 11, 2001 

Section B-3: Estimates of Emission Reductions for Domes 

Table B-6 – Potential Domed External Floating Roof Tanks with TVP >3psia 

and Estimated Emission Reductions (Note 3 and Note 4)

Facility No

of Tanks 

Emissions

(tpy) 

Emi Reduction

(tpy) 

Refinery #1 28 44.88 31.98

Refinery #2 47 127.82 76.47

Refinery #3 8 53.52 28.61

Refinery #4 28 73.89 48.49

Refinery #5 8 17.21 12.41

Refinery #6 3 5.70 3.98

Refinery #7 14 14.83 9.95

Other small 

refineries 

10 16.89 (Note 1) 10.59 (Note 1)

Non Refineries 95 240.90 151.10 (Note 2)

Total 241 595.64 (tpy)

1.63 (tpd) 

373.58 (tpy)

1.02 (tpd) 

Note: 1) Assume emissions and emission reductions of small refineries are about 5% of total 

emissions and emission reductions from other major refineries. 2) Emission reductions at non 

petroleum refineries = (emission reductions at 7 refineries) x (emissions at non refineries/emissions at 

7 refineries) = 211.89 tpy x (240.90/337.83) = 151.10 tpy. 3) The 373.58 tpy (1.02 tpd) reduction

shown in this table would be further reduced down to 324.21 tpy (0.89 tpd) as shown in the paragraphs 

below to remove the potential of double counting emission reductions associated with deck fittings, 

and emission reductions associated with doming crude oil tanks. 4) The number of potential domed 

tanks would be further reduced to 195 to exclude 46 crude oil tanks from doming requirements.

Estimate of Emission Reductions From Installing Domed Roofs on External 

Floating Roof Tanks Containing Organic Liquids with TVP >≥ 3 psia in Table 

5-1 and Scenario 1Staff Proposal (Scenario 1) inTable 6-6

Total emission reductions from upgrading deck fittings of all 526 EFRTs = 25.31 tpy. 

To be conservative in the cost effectiveness analysis, it is assumed that total emission 

reductions from upgrading deck fittings of 241 EFRTs containing materials having 

TVP >≥ 3 psia are 25.31 tpy. 

Total emissions reductions from retrofitting with domes after upgrading all deck fittings of 

241 EFRTs = 373.58 tpy - 25.31 tpy = 348.27 tpy = 0.95 tpd.

Total emissions reductions from retrofitting external floating roof tanks, excluding crude 

oil tanks, with domes = 348.27 tpy - 24.06 tpy = 324.21 tpy = 0.89 tpd.
Appendix B Final Staff Report 

Proposed Rule1178 B-9 December 11, 2001 

Estimate of Emission Reductions From Installing Domed Roofs on All External 

Floating Roof Tanks for Scenario 2 in Table 6-6

Total emission reductions from retrofitting with domes at 7 refineries = 222 tpy. 

Total emissions reductions from retrofitting with domes at 3 small refineries = (222 

tpy x 5% = 11 tpy. 

Total emission reductions from retrofitting with domes at non-refineries = 222 x 

(240.90/337.83) = 158 tpy. 

Total emission reductions with domes = 222 + 11 + 158 = 391 tpy 

Total emission reductions from retrofitting with domes after upgrading all deck 

fittings = 391 tpy - 25.31 tpy = 365.69 tpy. 

Section B-4: Emission Reductions for Retrofitting Fixed Roof 

Tanks with Floating Roofs or Vapor Recovery Systems

Table B-7 – Fixed Roof Tanks with TVP >0.1psia Currently Vented to the Atmosphere 

Facility No

of Tanks 

Emissions

(tpy) 

Emi Reduction at 

95% Control 

Efficiency 

(tpy) 

Refinery #1 6 26.19 24.88

Refinery #2 9 6.46 6.14 

Refinery #3 4 5.82 5.53

Non Refineries 51 26.16

Total 70 62.71 (tpy)

0.17 (tpd) 

Estimate of Emission Reductions From Converting Fixed Roof Tanks to 

Internal Floating Roof Tanks in Table 5-1 and Scenario 1Staff Proposal 

(Scenario 1) in Table 6-6

From Table 2-4, 2-5, and 2-6: 

Emissions from fixed roof tanks at petroleum refineries = 120.69 tpy 

Emissions from fixed roof tanks at non petroleum refineries = 37.08 + 49.29 = 86.37 tpy 

From Table B-6: 
Appendix B Final Staff Report 

Proposed Rule1178 B-10 December 11, 2001 

Emission reduction at petroleum refineries = 36.55 tpy 

Emission reduction at non petroleum refineries = 36.55 x (86.37/120.69) = 26.16 tpy

Estimate of Emission Reductions From Converting Fixed Roof Tanks to 

Internal Floating Roof Tanks in Scenario 2 in Table 6-6

From Table 2-4, 2-5, and 2-6: 

Emissions from fixed roof tanks at petroleum refineries = 120.69 tpy 

Emissions from fixed roof tanks at non petroleum refineries = 37.08 + 49.29 = 86.37 tpy 

Emission reduction from 133 fixed roof tanks at petroleum refineries = 83 tpy 

Emission reduction at non petroleum refineries = 83 x (86.37/120.69) = 59 tpy 

Section B-5: Emission Reductions and Source Testing for PressureVacuum Vents

Leakage rates from PV vents are reported in "Use of Pressure-Vacuum Vent Valves For 

Atmospheric Pressure Tanks To Reduce Evaporation Loss", API Bulletin #2521, September 

1966. From this document, leakage rate is reported as less than 0.5 cft/hr for vents 6 inches in 

size or smaller, or 5 cft/hr for vents 8 inches in size or larger. Assuming vapor density of 0.1 

lbs/cft, the leakage rates are estimated to be 0.05 lbs/hr (0.22 tpy) for vents 6 inches in size or 

smaller, or 0.5 lbs/hr (2.2 tpy) for vents 8 inches in size or larger. As an estimate for emission 

reductions from PV vents, District staff used a factor of 0.10 tpy per PV vents regardless of size 

and type. In order to verify the assumption used to estimate the emission reductions associated 

with PV vents, District staff conducted emissions sampling at two locations in the District. The 

testing and results are described below.

The testing consisted of measuring VOC emissions on three separate PV valves for 30 minutes 

each. The PV valves were located on fixed roof petroleum storage tanks connected to vapor 

recovery. Screening values were also measured before and after sampling by EPA Method 21. 

The relationship between measured emissions and screening value can be used to check the 

validity of existing emission factors and for correlating PV valve emissions. The results of the 

testing are summarized below. 

The PV valves sampled did not appear to be damaged and no leaks from the casing were noticed 

using the portable TVA. It appeared that the emissions were attributed to the valves not being 

properly seated. There was a noticeable amount of dirt and dust on and around the PV valve as 

observed by the District source test team at facility A. At facility B, the PV valve was relatively 

clean as compared to facility A. 
Appendix B Final Staff Report 

Proposed Rule1178 B-11 December 11, 2001 

Table B-8 - VOC Emissions from Fixed Roof Petroleum Storage Tanks

Tank # PV Valve

EPA Method 21 

Screening Value 

(PPM)

Emissions

(lbs/hr)

Facility A, Oriente Crude Varac – 12 inch >100,000 9.81

Facility A, Oriente Crude Protectoseal – 8 inch >100,000 2.52

Facility B, Naphtha Varac – 8 inch 325 0.0051

Note: Emissions are 42.96 tpy, 11.04 tpy and 0.02 tpy respectively for 24 hrs/day, 365 days/yr.

Both facilities have numerous tanks that store petroleum products including crude oil, naptha, 

diesel, and gasoline. The tanks tested all were fixed roof tanks containing Oriente crude oil, and 

naphtha having vapor pressures between 2 and 5 psi. The fixed roof storage tanks sampled 

contained multiple 8” and 12” PV valves set for 3⁄4 oz./sq. in. (.0625 psi) pressure and vacuum. 

For each storage tank, the testing was performed on one PV valve. One of the storage tanks 

contained Varac 12” PV valves set for 3⁄4 oz. pressure/vacuum. The second storage tank had 

Protectoseal 8” PV valves set for 3⁄4 oz. pressure/vacuum. The final PV valve sampled was a 

Varac 8” PV valve set for 3⁄4 oz. pressure/vacuum. These tests were conducted in accordance 

with applicable SCAQMD and EPA test methodologies. Both storage tanks were tested under 

normal operating conditions. 

For fugitive emissions from the storage tanks, a procedure analogous to the "Vacuum Method" 

from the EPA Protocol for Equipment Leaks Estimates was employed. The PV valves on the 

tops of the storage tanks were identified as potential sources of fugitive emissions. For each test,

a wood framed plastic tent was placed over the PV valve and attached with adhesive tape to the 

tank roof to isolate it from the surroundings. The pressure inside of the enclosure relative to 

ambient was not lower than -0.01 inches water column as measured by a calibrated electronic 

manometer during testing. Since the tent covered the entire PV valve, any emissions from the 

pressure side and from the vacuum side of the valve were tested simultaneously. 

The emissions of VOC were continuously withdrawn from the enclosure with either a manually 

or battery operated blower to draw air through the system. To prevent an explosion, the manually 

operated blower was used when it was determined that emissions were at the chemical’s LEL. 

Air was allowed to enter the tent through an opening in the tent located on its upwind side. The 

flow rate, concentration, and mass emissions from the PV valves were measured at the blower 

outlet duct using SCAQMD Methods 1.1, 2.1, and 25.3.

A portable flame ionization detector (FID) was used during sampling and screening the PV 

valves, monitoring duct concentration, monitoring background levels and checking for tent 

fugitive emissions. While these portable FID readings were not used in calculating emissions, the 

values that were recorded are located in the field notes. The specifics of each sampling and 
Appendix B Final Staff Report 

Proposed Rule1178 B-12 December 11, 2001 

analytical method employed are given in the sections that follow. In addition, the start and end 

times of each test run were recorded.
Appendix C Final Staff Report 

Proposed Rule1178 C-1 December 11, 2001 

Appendix C - Cost Effectiveness Analysis 

Section C-1: Domed External Floating Roof Tanks 

Scenario 1Staff 

Proposal (Scenario 1)

(Control EFRTs with 

TVP >≥3 psia, 

excluding crude oil 

tanks) 

Scenario 2The most 

stringent proposal 

(Scenario 2) (Control 

All EFRTs, including 

crude oil tanks) 

Tank Diameter ft 30 - 260 30 - 260 

No of tanks 241195 (146 refineries 

and 95 non-refineries)

526 (383 refineries and 

143 non-refineries)

Emission Reduction tpy 348.27324.21 365.69 

CAPITAL COST 

Equipment Cost As Installed Including Taxes 

and Freight 

$ 49,780,99333,594,943 108,650,632 

Tax (8% Equipm.Cost)Permit Cost ($2,115.04 

per application)

$ 0412,433 01,112,511

Freight (3.8% Equipm.Cost)Project 

Management (5% Equip. Cost)

$ 01,679,747 05,432,532

Loss of Use (Based on a lease rate of 1.5 

cents/barrels-day) 

$ 19,129,56811,041,053 19,129,56813,445,036

Total Capital Cost (Equipment Cost As 

Installed Including Taxes and Freight + Loss 

of Use)

$ 68,910,56146,728,176 127,780,200128,640,711

ANNUAL OPERATING COST 

Annual Maintenance Cost (1% Equipm.Cost) $/yr 497,810335,949 1,086,506 

Annual Insurance and Property Taxes (12% 

Capital Cost) 

$/yr 689,106934,564 1,277,8022,572,814

Annual Emission Savings ($819.11/ton) $/yr 265,564 299,540

Product Savings at $200/ton $/yr 69,65464,842 73,138 

Inspection Savings $/yr 15,600 42,080

Total Annual Operating Cost With Product 

Savings (Annual Maintenance + Insurance - 

Annual Emission Savings - Product Savings -

Inspection Savings) 

$/yr 1,117,262924,507 2,291,1703,244,562

PRESENT WORTH VALUE 
Appendix C Final Staff Report 

Proposed Rule1178 C-2 December 11, 2001 

 With Product Savings $ 84,094,14559,292,230 158,917,205172,734,311

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / 

(EmiReductionx20)) 

$/ton 12,0739,144 21,72823,618
Appendix C Final Staff Report 

Proposed Rule1178 C-3 December 11, 2001 

Section C-2: Rim Seal Systems 

Scenario 1Staff 

Proposal 

(Scenario 1)

Scenario 2The most 

stringent proposal 

(Scenario 2)

Primary 

Seals 

Secondary 

Seals 

Primary 

Seals 

Secondary 

Seals 

True Vapor Pressure of Materials Stored >0.1psia >0.1psia All All 

Tank Diameter ft 127 127 127 127 

Tank Circumference ft 399 399 399 399 

No of Tanks 3 9 3 66 

CAPITAL COST 

Cost of Rim Seals Per Linear Foot As Installed $/ft 107 98 107 98 

Total Cost of Rim Seals $ 128,074 351,903 128,074 2,580,623 

Tax (8% Cost of Rim Seals) $ 10,246 28,152 10,246 206,450 

Total Capital Cost (Cost of Rim Seals As Installed+

Tax) 

$ 138,319 380,055 138,319 2,787,073 

ANNUAL OPERATING COST 

Annual Maintenance Cost (8hr/day at $30/hr for 1 

tank for secondary seals) 

$/yr 0 2,160 0 15,840 

Product Savings at $200/ton $/yr 802 2,334 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance - Product Savings) 

$/yr 1,358 13,506 

PRESENT WORTH VALUE 

With Product Savings (assuming 10 years life and 

4% interest rate; PWV = Capital Cost + 

(8.11*Annual Operating Cost)) 

$ 529,388 3,034,926 

COST EFFECTIVENESS FACTOR 

Emi Reduction tpy 4 12 

With Product Savings (PWV / 

(EmiReductionx10)) 

$/ton 13,202 26,006 
Appendix C Final Staff Report 

Proposed Rule1178 C-4 December 11, 2001 

Section C-3: Deck Fittings for External Floating Roof Tanks 

Scenario 1Staff Proposal (Scenario 1) - External 

Floating Roof Tanks 

Type of Fittings Other Fittings Guidepoles All 

No of Fittings Need to Be Upgraded 6,281 274 6,555

Emissions Reduction tpy 25.31 

CAPITAL COST 

Cost of Upgrading Per Fitting $ 500 10,000 

Cost of Upgrading All Fitting $ 3,140,500 2,740,000 5,880,500 

Tax (8% Cost of Upgrading Fittings) $ 251,240 219,200 470,440 

Percentage to Determine Installation Cost (A%) % 10 0 

Installation (A% Cost of Upgrading Fittings) $ 314,050 0 314,050 

Total Capital Cost (Cost of Upgrading Fittings + Tax + 

Installation) 

$ 3,705,790 2,959,200 6,664,990 

ANNUAL OPERATING COST 

Annual Maintenance Cost (8hr/day, $30/hr) $/yr 240 

Product Savings at $200/ton $/yr 5,062 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance - Product Savings) 

$/yr -4,822 

PRESENT WORTH VALUE 

 With Product Savings $ 6,625,884 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / (EmiReductionx10)) $/ton 26,179 
Appendix C Final Staff Report 

Proposed Rule1178 C-5 December 11, 2001 

Section C-3 (continued) 

Scenario 2The most stringent proposal (Scenario 2) - 

External Floating Roof Tanks 

Type of Fittings Others Guidepoles All 

No of Fittings Need to Be Upgraded 7,252 287 7,539

Emissions Reduction tpy 25.31 

CAPITAL COST 

Cost of Upgrading Per Fitting $ 500 10,000 

Cost of Upgrading All Fitting $ 3,626,000 2,870,000 6,496,000 

Tax (8% Cost of Upgrading Fittings) $ 290,080 229,600 519,680 

Percentage to Determine Installation Cost (A%) % 10 0 

Installation (A% Cost of Upgrading Fittings) $ 362,600 0 362,600 

Total Capital Cost (Cost of Upgrading Fittings + Tax 

+ Installation) 

$ 4,278,680 3,099,600 7,378,280 

ANNUAL OPERATING COST 

Annual Maintenance Cost (8hr/day, $30/hr) $/yr 240 

Product Savings at $200/ton $/yr 5,062 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance - Product Savings) 

$/yr -4,822 

PRESENT WORTH VALUE 

 With Product Savings $ 7,339,174 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / 

(EmiReductionx10)) 

$/ton 28,997 
Appendix C Final Staff Report 

Proposed Rule1178 C-6 December 11, 2001 

Section C-4: Deck Fittings for Internal Floating Roof Tanks 

Scenario 1Staff Proposal (Scenario 1)- 

Internal Floating Roof Tanks 

Type of Fittings Other 

Fittings 

Guidepoles All 

No of Fittings Need to Be Upgraded 1,057 172 1,229

Emissions Reduction tpy 40.44 

CAPITAL COST 

Cost of Upgrading Per Fitting $ 500 10,000 

Cost of Upgrading All Fitting $ 528,500 1,720,000 2,248,500 

Tax (8% Cost of Upgrading Fittings) $ 42,280 137,600 179,880

Percentage to Determine Installation Cost (A%) % 10 0 

Installation (A% Cost of Upgrading Fittings) $ 52,850 0 52,850 

Total Capital Cost (Cost of Upgrading Fittings + Tax + 

Installation) 

$ 623,630 1,857,600 2,481,230 

ANNUAL OPERATING COST 

Annual Maintenance Cost (8hr/day, $30/hr) $/yr 240 

Product Savings at $200/ton $/yr 8,088 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance - Product Savings) 

$/yr -7,848 

PRESENT WORTH VALUE 

 With Product Savings $ 2,417,583 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / (EmiReductionx10)) $/ton 5,978 
Appendix C Final Staff Report 

Proposed Rule1178 C-7 December 11, 2001 

Section C-4 (continued) 

Scenario 2The most stringent proposal 

(Scenario 2)- Internal Floating Roof Tanks 

Type of Fittings Others Guidepoles All 

No of Fittings Need to Be Upgraded 1,207 186 1,393

Emissions Reduction tpy 40.44 

CAPITAL COST 

Cost of Upgrading Per Fitting $ 500 10,000 

Cost of Upgrading All Fitting $ 603,500 1,860,000 2,463,500 

Tax (8% Cost of Upgrading Fittings) $ 48,280 148,800 197,080 

Percentage to Determine Installation Cost (A%) % 10 0 

Installation (A% Cost of Upgrading Fittings) $ 60,350 0 60,350 

Total Capital Cost (Cost of Upgrading Fittings + Tax + 

Installation) 

$ 712,130 2,008,800 2,720,930 

ANNUAL OPERATING COST 

Annual Maintenance Cost (8hr/day, $30/hr) $/yr 240 

Product Savings at $200/ton $/yr 8,088 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance - Product Savings) 

$/yr -7,848 

PRESENT WORTH VALUE 

 With Product Savings $ 2,657,283 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / (EmiReductionx10)) $/ton 6,571 
Appendix C Final Staff Report 

Proposed Rule1178 C-8 December 11, 2001 

Section C-5: Internal Floating Roof Tanks 

Scenario 1Staff 

Proposal 

(Scenario 1)

Scenario 2The 

most stringent 

proposal (Scenario 

2)

No of tanks 70 296 

Emissions Reduction tpy 62.71 142 

CAPITAL COST 

Equipment Cost As Installed Including Taxes, Freight, 

Engineering and Installation 

$ 7,663,158 32,404,211 

Loss of Use (40% Equipm Cost) $ 3,065,263 12,961,684 

Total Capital Cost (Equipment Cost + Tax + Freight + 

Engineering + Installation + Loss of Use) 

$ 10,728,421 45,365,895 

ANNUAL OPERATING COST 

Annual Maintenance Cost (3% Equipm.Cost) $/yr 229,895 972,126 

Annual Insurance (1% Capital Cost) $/yr 107,284 453,659 

Product Savings at $200/ton $/yr 12,542 28,400 

Total Annual Operating Cost With Product Savings 

(Annual Maintenance + Insurance - Product Savings) 

$/yr 324,637 1,397,385 

PRESENT WORTH VALUE 

With Product Savings (assuming 20 years life and 4%

interest rate; PWV = Capital Cost + (13.59*Annual 

Operating Cost)) 

$ 15,140,237 64,356,360 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / (EmiReductionx20)) $/ton 12,072 22,661 
Appendix C Final Staff Report 

Proposed Rule1178 C-9 December 11, 2001 

Section C-6: Pressure-Vacuum Vents 

Scenario 1Staff Proposal 

(Scenario 1) 

Scenario 2The most 

stringent proposal 

(Scenario 2) 

No of PV Vents 532 532 

Emissions Reduction Per PV Vents tpy 0.10 0.10 

Emissions Reduction tpy 53.20 53.20 

CAPITAL COST 

Total Capital Cost (Total Cost of PV Vents + Tax 

+ Installation) 

$ 0 0 

ANNUAL OPERATING COST 

Annual Maintenance Cost ($500 per PV vents) $/yr 266,000 266,000 

Product Savings at $200/ton $/yr 10,640 10,640 

Total Annual Operating Cost With Product 

Savings (Annual Maintenance - Product Savings) 

$/yr 255,360 255,360 

PRESENT WORTH VALUE 

With Product Savings (assuming 10 years life and 

4% interest rate; PWV = capital cost + 

(8.11*annual operating cost)) 

$ 2,070,970 2,070,970 

COST EFFECTIVENESS FACTOR 

With Product Savings (PWV / 

(EmiReductionx10)) 

$/ton 3,893 3,893 
Appendix D Final Staff R

Proposed Rule 1178 D-1 December 11

Appendix D - Impact Study on Doming of External Floating Roof Tanks 

Table D-1: Tank Removal and Capacity Removal At Refineries Based on Doming Including Crude Oil Tanks

Refinery No of 

EFRTs 

Capacity of 

EFRTs 

No of 

IFRTs

Capacity 

of IFRTs 

No of 

FRTs 

Capacity of 

FRTs 

Total No of 

Tanks 

(including 

existing 

Domed 

EFRTs) 

Total 

Tank 

Capacity 

No of 

Potential 

Domed 

EFRTs 

Tank % (4 Years of Construction 

Using External 

Floating Roof 

Tanks) 

Capacity % (4 

Years of 

Construction 

Using Capacity of 

External Floating 

Roof Tanks) 

Tank % (4 

Years of 

Construction 

Using All 

Tanks) 

Capacity 

Years 

Constru

Using Ca

of All Ta

Next Vext 

(million 

barrels) 

Nint Vint 

(million 

barrels) 

Nfix Vfix (million 

barrels) 

Ntotal Vtotal 

(million 

barrels) 

Ndomed (Ndomed/(4* 

Next) 

((Sum (Vdomed 

*D) / (Vext *365 * 

4))*100 

(Ndomed/(4*Nto

tal) 

((Sum (Vd

*D) / (Vtot

* 4))*1

1 50 4.68 4 0.70 55 6.22 109 11.60 28 14 2.13 6 0.86 2 111 17.53 13 0.38 68 0.00 192 17.92 47 11 1.56 6 1.52 3 13 1.14 1 0.00 92 4.97 107 6.11 8 15 1.58 2 0.29 4 66 5.17 1 0.16 45 3.40 114 8.73 28 11 1.80 6 1.07 5 29 4.23 2 0.16 3 0.24 34 4.62 8 7 2.05 6 1.88 6 87 6.47 0 0.00 4 0.28 95 6.75 3 1 0.13 1 0.12 7 27 2.87 0 0.00 10 0.26 37 3.13 14 13 2.34 9 2.15 

383 42.09 21 1.39 277 15.36 688 58.85 136 9 5 

AVG 10 1.66 5 1.13 

Note: Next = Number of external floating roof tanks, Vext = Capacity of external floating roof tanks, Nint = Number of internal floating roof tanks, Vint = Capacity of internal floating roof tanks, Nfix = Number of fitanks, Vfix = Capacity of fixed roof tanks, Ndomed = Number of potential domed roof tanks, Vdomed = Capacity of domed roof tanks, D = number of days for construction of domed roofs. 
Appendix D Final Staff Report 

Proposed Rule 1178 D-2 December 11, 2001 

Figure D-1: Capacity Removal At Refineries Based on Doming - Considering All Types of 

Tanks And Including Crude Oil Tanks

Capacity Removal (All Tanks)

0.00

0.50

1.00

1.50

2.00

2.50

1 2 3 4 5 6 7

Refinery

4 Years Plan

Average = 1.13
Appendix D Final Staff Report 

Proposed Rule 1178 D-3 December 11, 2001 

Figure D-2: Capacity Removal At Refineries Based on Doming - Considering All External 

Floating Roof Tanks and Including Crude Oil Tanks

Capacity Rem oval (EFR Ts O nly)

0.00

0.50

1.00

1.50

2.00

2.50

1 2 3 4 5 6 7

R efinery

Capacity Removal (%)

4 Y ears P lan

Avg = 1.66
Appendix D Final Staff Report 

Proposed Rule 1178 D-4 December 11, 2001 

Figure D-3: Tank Removal At Refineries Based on Doming - Considering All Types of 

Tanks And Including Crude Oil Tanks

Tank Removal 

(All Tanks)

0

1

2

3

4

5

6

7

8

9

10

1 2 3 4 5 6 7

Refinery

Tank Removal (%)

Tank Removal

Avg Tank Removal = 5%
Appendix D Final Staff Report 

Proposed Rule 1178 D-5 December 11, 2001 

Figure D-4: Tank Removal At Refineries Based on Doming - Considering All External 

Floating Roof Tanks and Including Crude Oil Tanks

Tank Removal 

(EFRTs Only)

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Non-Refinery

Tank Removal (%)

Tank Removal

Avg Tank Removal = 21%
Appendix D Final Staff R

Proposed Rule 1178 D-6 December 11, 

Table D-2: Tank Removal and Capacity Removal At Non-Refineries Based on Doming Including Crude Oil Tanks

Facility No of 

EFRTs

Capacity of 

EFRTs 

No of 

IFRTs 

Capacity of 

IFRTs 

No of 

FRTs 

Capacity of 

FRTs 

Total No 

of Tanks 

Total Tank 

Capacity 

No of 

Potential 

Domed 

EFRTs 

Capacity of 

Potential Domed 

EFRTs 

Tank % (4 Years of 

Construction Using 

External Floating 

Roof Tanks) 

Capacity % (4 Years 

of Construction 

Using Capacity of 

External Floating 

Roof Tanks) 

Tank % (4 

Years of 

Construction 

Using All 

Tanks) 

Capacity % 

Years o

Construction 

Capacity o

Tanks) 

Next Vext (million 

barrels) 

Nint Vint (million 

barrels) 

Nfix Vfix (million 

barrels) 

Ntotal Vtotal 

(million 

barrels) 

Ndomed Vdomed (million 

barrels) 

(Ndomed/(4*Next)) ((Sum (Vdome *D) / 

(Vext *365 * 4))*100 

(Ndomed/(4*Nt

otal)) 

((Sum (Vdom

(Vtotal *36

4))*100 

5 10 0.99 0 0.00 2 0.06 12 1.05 9 0.94 23 2.87 19 2.72 8 2 0.20 18 1.00 0 0.00 20 1.20 2 0.20 25 2.19 3 0.37 

11 24 1.90 6 0.10 0 0.00 30 2.00 15 1.43 16 2.89 13 2.74 19 2 0.02 1 0.04 0 0.00 3 0.05 2 0.02 25 2.60 17 0.80 

4 8 0.36 0 0.00 2 0.16 10 0.51 6 0.35 19 2.68 15 1.86 

10 6 0.23 27 2.24 76 1.01 109 3.48 4 0.23 17 3.38 1 0.22 22 2 0.22 7 0.26 0 0.00 9 0.48 2 0.22 25 2.81 6 1.28 

7 4 0.27 6 0.57 7 0.15 17 0.98 2 0.13 13 0.52 3 0.14 

31 2 0.05 1 0.04 1 0.03 4 0.12 2 0.05 25 13 

2 11 0.28 23 0.68 2 0.03 36 1.04 9 0.32 20 0.87 6 0.24 1 5 0.21 10 0.60 0 0.00 15 0.81 5 0.21 25 3.09 8 0.80 6 11 1.31 31 2.99 8 1.10 50 5.41 11 0.56 25 1.60 6 0.39 

17 8 0.37 5 0.25 2 0.09 15 0.71 7 0.08 22 2.26 12 1.18 

9 8 0.09 0 0.00 2 0.03 10 0.11 7 0.09 22 4.27 18 3.27 3 21 2.10 0 0.00 0 0.00 21 2.10 16 1.60 19 2.55 19 2.55 

124 8.59 135 8.77 102 2.64 361 20.04 99 note 6.42 20 7 

AVG 21 2.47 10 1.33 

Note: Next = Number of external floating roof tanks, Vext = Capacity of external floating roof tanks, Nint = Number of internal floating roof tanks, Vint = Capacity of internal floating roof tanks, Nfix = Number of fixed roof tanks, Vfix = Capacity of fixed roof tanks, Ndomed = Number of potential domed roof tanks, Vdomed = Capacity of domed roof tanks, D = number of 

days for construction of domed roofs. This number (99) included several tanks that are already domed.
Appendix D Final Staff Report 

Proposed Rule 1178 D-7 December 11, 2001 

Figure D-5: Capacity Removal At NonRefineries Based on Doming - Considering 

All Types of Tanks And Including Crude Oil Tanks

C ap acity R em o val 

(A ll Tan ks)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

5 8 11 1 9 4 10 2 2 7 3 1 2 1 6 17 9 3

N on-R efinery

Capacity Removal (%)

C a pa city R em o val

A vg C a pa city R e m oval = 1 .3 3 %
Appendix D Final Staff Report 

Proposed Rule 1178 D-8 December 11, 2001 

Figure D-6: Capacity Removal At NonRefineries Based on Doming - Considering 

Only External Floating Roof Tanks And Including Crude Oil Tanks

Capacity Rem oval 

(EFRTs O nly)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5 8 11 19 4 10 22 7 31 2 1 6 17 9 3

Non-R efinery

Capacity Removal (%)

C apacity R em oval

Avg Capacity R em oval = 2.47%
Appendix D Final Staff Report 

Proposed Rule 1178 D-9 December 11, 2001 

Figure D-7: Tank Removal At Non-Refineries Based on Doming -

Considering All Types of Tanks And Including Crude Oil Tanks

Tank Removal 

(All Tanks)

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Non-Refinery

Tank Removal (%)

Tank Rem oval

Avg Tank Rem oval = 10%
Appendix D Final Staff Report 

Proposed Rule 1178 D-10 December 11, 2001 

Figure D-8: Tank Removal At Non-Refineries Based on Doming - Considering 

Only External Floating Roof Tanks And Including rude Oil Tanks 

Tank Removal 

(EFRTs Only)

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Non-Refinery

Tank Removal (%)

Tank Removal

Avg Tank Removal = 21%
Appendix D Final Staff Report 

Proposed Rule 1178 D-11 December 11, 2001 

Table D-3: Tank Removal and Capacity Removal At Refineries Based on Doming Excluding Crude Oil Tanks 

Facility Name No of 

EFRTs 

No of 

Crude Tanks 

No of EFRTs 

Excluding 

Crude 

Tanks 

EFRTs Crude Tanks EFRTs Excluding 

Crude Tanks 

No of 

Potential 

Domed 

EFRTs 

No of 

Potential 

Domed 

EFRTs 

Excluding 

Crude 

Tank % (4 Years 

of 

Construction 

Using External 

Floating Roof 

Tanks including 

crude tanks) 

Tank % (6 

Years of 

Construction 

Using External 

Floating Roof 

Tanks, 

excluding 

crude tanks) 

Capacity % (4 

Years of 

Construction 

Using Capacity 

of External 

Floating Roof 

Tanks) 

Capacity % (6 

Years of 

Construction 

Using Capacity of 

External Floating 

Roof Tanks 

excluding crude 

tanks) 

Next Ncrude Next, 

nocrude 

Vext (gals) Vcrude (gals) Vext,nocrude(gals) Ndomed Ndomed, no 

crude 

(Ndomed/(4*Ne

xt) 

(Ndomed, 

nocrude/(6*Nex

t, nocrude) 

((Sum (Vdomed 

*D) / (Vext *365 

* 4))*100 

((Sum 

(Vdomed,nocrude*

D) / (Vext,nocrude 

*365 * 6))*100 

1 50 7 43 196,697,634 52,837,344 143,860,290 28 21 14 8 2.13 0.89 2 111 7 104 736,394,000 104,819,400 631,574,600 47 40 11 6 1.56 0.45 3 13 0 13 47,964,000 0 47,964,000 8 8 15 10 1.58 0.94 4 66 3 63 216,976,410 14,253,372 202,723,038 28 25 11 7 1.80 0.99 5 29 6 23 177,521,449 83,563,200 93,958,249 8 2 7 1 2.05 0.09 6 87 0 87 271,716,018 0 271,716,018 3 3 1 1 0.13 0.07 7 27 5 22 120,540,000 50,400,000 70,140,000 14 9 13 7 2.34 0.73 

TOTAL 383 28 355 136 108 9 5 

AVG 10 6 1.66 0.59 
Appendix D Final Staff Report 

Proposed Rule 1178 D-12 December 11, 2001 

Table D-4: Tank Removal and Capacity Removal At Non-Refineries Based on Doming Excluding Crude Oil Tanks 

Facility No of 

EFRTs 

No of 

Crude 

Tanks 

No of 

EFRTs 

Exvluding 

Crude 

Tanks 

EFRTs CrudeTanks EFRTs Excluding 

Crude Tanks 

No of 

Potential 

Domed 

EFRTs 

No of 

Potential 

Domed 

EFRTs 

Excluding 

Crude Tanks

Tank % (4 

Years of 

Construction 

Using External 

Floating Roof 

Tanks) 

Tank % (6 

Years of 

Construction 

Using External 

Floating Roof 

Tanks, 

Excluding 

Crude Tanks) 

Capacity % (4 

Years of 

Construction 

Using Capacity 

of External 

Floating Roof 

Tanks) 

Capacity % (6 Years 

of Construction 

Using Capacity of 

External Floating 

Roof Tanks, 

Excluding Crude 

Tanks) 

Next Ncrude Next,no 

crude 

Vext (gals) Vcrude 

(gals) 

Vext,no crude 

(gals) 

Ndomed Ndomed,no 

crude 

(Ndomed/(4*Ne

xt)) 

(Ndomed/(6*Ne

xt,no crude)) 

((Sum (Vdome 

*D) / (Vext *365 

* 4))*100 

((Sum 

(Vdome,nocrude *D) 

/ (Vext *365 * 6))*100

5 10 0 10 41,606,000 0 41,606,000 9 9 23 15 2.87 1.918 2 0 2 8,400,000 0 8,400,000 2 2 25 17 2.19 1.46

11 24 7 17 79,766,000 63,188,580 16,577,420 15 8 16 8 2.89 2.4219 2 0 2 684,600 0 684,600 2 2 25 17 2.60 1.74

4 8 0 8 14,998,800 0 14,998,800 6 6 19 13 2.68 1.78

10 6 0 6 9,704,370 0 9,704,370 4 4 17 11 3.38 2.2522 2 0 2 9,156,000 0 9,156,000 2 2 25 17 2.81 1.87

7 4 0 4 11,256,000 0 11,256,000 2 2 13 8 0.52 0.35

31 2 0 2 2,070,000 0 2,070,000 2 2 25 17

2 11 0 11 11,739,000 0 11,739,000 9 9 20 14 0.87 0.581 5 0 5 8,799,000 0 8,799,000 5 5 25 17 3.09 2.066 11 2 9 55,104,000 6,553,680 48,550,320 11 9 25 17 1.60 0.97

17 8 0 8 15,552,000 0 15,552,000 7 7 22 15 2.26 1.51

9 8 0 8 3,584,000 0 3,584,000 7 7 22 15 4.27 2.853 21 4 17 88,200,000 20,531,280 67,668,720 16 12 19 12 2.55 1.66

124 13(Note) 111 99(Note) 86 13

AVG 21 14 2.47 1.67

Note: These numbers include several tanks that are already domed.
Appendix E Final Staff Report 

Proposed Rule 1178 E-1 December 11, 2001 

Appendix E - Comparative Analysis 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Applicability 

PR 1178 R.463 40CFR60 BAAQMD 

Above ground storage tanks at 

petroleum facilities emitting 

20tpy or more as of inventory 

year 1999, equal to or greater 

than 19,815 gallons, that are 

used to store petroleum liquids 

with a vapor pressure of 0.1 psia 

or greater. 

Storage tanks from 19,815 

gallons to 39,630 gallons 

containing organic liquids 

with a vapor pressure of 1.5 

psia or greater. 

Storage tanks from 39,630 

gallons containing organic 

liquids with a vapor pressure 

of 0.5 psia or greater. 

Storage tanks from 251 gal to 

19,815 gal storing gasoline. 

Subpart K 

Storage tanks from 40,000 

gallons to 65,000 gallons 

built after 3/8/74, but before 

5/19/78, containing 

petroleum liquids with a 

vapor pressure of 1.5 psia to 

11.1 psia. 

Storage tanks from 40,000 

gallons to 65,000 gallons 

built after 3/8/74, but before 

5/19/78, containing 

petroleum liquids with a 

vapor pressure of 1.5 psia to 

11.1 psia. 

Storage tanks from 65,000 

gallons built after 6/11/73 but 

before 5/19/78, containing 

petroleum liquids with a true 

vapor pressure of 1.5 psia up 

to 11.1 psia. 

Subpart Ka 

Storage tanks from 40,000 

gallons built after 5/18/78 

and prior to 7/23/84, 

containing petroleum liquids 

with a true vapor pressure of 

1.5 psia up to 11.1 psia. 

Subpart Kb 

Storage tanks built after 

7/23/84, containing volatile 

organic liquids (including 

petroleum liquids) from 

19,185 gallons up to 39,889 

gallons with a vapor pressure 

between 4 psia and 11.1 psia 

and storage tanks greater than 

39,889 gal with a maximum 

vapor pressure between 0.75 

psia and 11.1 psia. 

Storage Tanks between 9906 

gallons and 19,813 gallons 

storing a liquid with a true 

vapor pressure greater than 

1.5 psia. 

Storage Tanks between 

19,813 gallons and 39,626 

gallons storing a liquid with 

true vapor pressure greater 

than 1.5 psia. 

Storage Tanks with a 

capacity less than or equal to 

39,626 gallons storing a 

liquid with a true vapor 

pressure greater than 0.5 psia. 

Storage Tanks with capacity 

equal to or greater than 

39,626 gallons with a true 

vapor pressure greater than 

0.5 psia. 

Gasoline Storage Tanks less 

than or equal to 19,813 

gallons. 

Storage tanks with a true 

vapor pressure greater than 

11 psia. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-2 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD Regulation 8, Rule 5 

External Floating Roof Tank Requirements (Seals/Gaps) 

PR 1178 R.463 40CFR60 BAAQMD 

Rim seal system consisting of 

two seals, covering the annular 

space between the floating roof 

and the tank wall in a continuous 

fashion. 

Liquid mounted primary seals 

for both welded and riveted 

tanks. 

Secondary seals shall be rimmounted. 

Rim seal system to cover the 

annular space between the 

floating roof and the wall in a 

continuous fashion. 

Primary Seal

Gaps between the tank shell and 

the primary seal shall not exceed 

1.3 cm (1/2 in.) for a cumulative 

length of 30% of the tank 

circumference and 0.32 cm (1/8 

in.) for 60% of the tank 

circumference. 

No gap b/w the tank shell and 

the primary seal shall exceed 3.8 

cm (1-1/2 in.). 

No continuous gap b/w the tank 

shell and the primary seal shall 

exceed 10% of the tank 

circumference. 

Mechanical shoe primary seals 

shall be installed so that one end 

of the shoe extends into the 

stored liquid and the other end 

extends a minimum vertical 

distance of 61 cm (24 in.) above 

the stored organic liquid. 

Secondary Seal

Gaps between the tank shell and 

the secondary seal shall not 

exceed 0.32 cm (1/8 in.) for a 

cumulative length of 95% of the 

tank circumference. No gap 

between the tank shell and the 

secondary seal shall exceed 1.3 

cm (1/2 in.). 

The secondary seal shall be 

installed in a way that permits 

the insertion of probes up to 3.8 

cm (1-1/2 in.) in width to 

measure gaps in the primary 

seal. 

Two seals, one above the 

other. 

Metallic shoe-type primary 

seals installed on or after 

August 1, 1977 shall be 

installed so that one end of the 

shoe extends into the stored 

organic liquid and the other 

end extends a minimum 

vertical distance of 61 

centimeters (24 inches) above 

the stored organic liquid 

surface. 

No specification for other 

types of primary seals. 

(Gap requirements for 

primary and secondary seals 

same as Proposed Rule 

1178). 

Secondary seals shall not be 

attached to the primary seal. 

Both seals may be removed 

for preventive maintenance 

upon notification of the E.O. 

for a period of up to 72 hours. 

There shall be no holes, tears 

or openings in the secondary 

seal or in the primary seal 

envelope surrounding the 

annular vapor space enclosed 

by the roof edge, seal fabric, 

and secondary seal. 

Subpart K 

No seal specs. Given 

Subpart Ka 

The closure device has to 

consist of 2 seals, one above 

the other. The floating roof 

has to be floating on the 

liquid at all times, except 

during emptying or refilling. 

The primary seal can either 

be a metallic shoe seal, a 

liquid-mounted or a vapor 

mounted seal. 

For tanks with metallic shoe, 

one end of the metallic shoe 

is to extend into the stored 

liquid and the other end is to 

extend a minimum vertical 

distance of 61 cm (24 in) 

above the stored liquid 

surface. 

There are to be no holes, 

tears, or other openings in the 

shoe, seal fabric, or seal 

envelope 

The secondary seal type is 

not specified. 

Subpart Kb 

The closure device consists 

of 2-seals, one above the 

other. The floating roof has 

to float on the liquid at all 

times, except during 

emptying or refilling. 

Primary seals may be 

metallic shoe or liquid 

mounted. Secondary seals 

must cover the annular space 

between the rim and the tank 

wall in a continuous fashion. 

Primary and secondary seals 

need to meet certain gap 

criteria. 

There are to be no holes, 

tears, or other openings in the 

shoe, seal fabric, or seal 

envelope. 

An external floating roof 

tank shall be equipped 

with a primary and 

secondary seal. 

Primary Seal

The primary seal fabric 

shall have no holes, tears 

or other openings, which 

would allow the emission 

of organic vapors. 

The primary seal may be 

liquid-mounted or may be 

of the metallic shoe type. 

Metallic shoe type seals 

shall be installed so that 

one end of the shoe 

extends a minimum 

vertical distance of 61 cm 

(24 in.). 

For welded tanks, no gap 

between the tank shell and 

the primary seal shall 

exceed 3.8 cm (1-1/2 in.); 

No continuous gap greater 

than 0.32 cm (1/8 in.) 

shall exceed 10% of the 

circumference of the tank. 

The cumulative length of 

all primary seal gaps 

exceeding 1.3 cm (1/2 in.) 

shall not be more than 

10% of the circumference. 

The cumulative length of 

all primary seal gaps 

exceeding 0.32 cm (1/8 

in.) shall not be more than 

40% of the circumference. 

For riveted tanks, no gap 

between the tank shell and 

the primary seal shall 

exceed 6.4 cm (2-1/2 in). 

The cumulative length of 

all primary seal gaps 

exceeding 3.8 cm (1-1/2 

in.) shall not be more than 

10% of the circumference. 

Secondary Seals

The secondary seal shall 

allow easy insertion of 

probes. up to 3.8 cm (1-

1/2 in.) in width in order 

to measure gaps in the 

primary seal. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-3 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

External Floating Roof Tank Requirements (Seals/Gaps continued) 

PR 1178 R.463 40CFR60 BAAQMD 

The shall be no holes, tears or 

openings in the secondary seal or 

in the primary seal envelope 

surrounding the annular vapor 

space enclosed by the roof edge, 

seal fabric and the secondary 

seal. 

For welded tanks, no gap 

between the tank shell and 

the secondary seal shall 

exceed 1/3 cm (1/2 in.). 

The cumulative length of 

all secondary seal gaps 

exceeding 0.32 cm (1/2 

in.) shall not be more than 

5% of the circumference 

of the tank. 

For welded external 

floating roof tanks with 

seals installed after 

9/4/85, no gap between 

the tank shell and the 

secondary seal shall 

exceed 1.5 mm (0.06 in.). 

The cumulative length of 

all secondary seal gaps 

exceeding 0.5 mm (0.02 

in.) shall be no more than 

5% of the circumference 

of the tank, excluding 

gaps less than 5 cm (1.79 

in.) from vertical weld 

seams. 

For riveted tanks, the 

secondary seal shall 

consist of at least two 

sealing surfaces, such that 

the sealing surfaces 

prevent the emission of 

organic compounds 

around the rivets. 

Serrated surfaces are 

allowed if the length of 

the serration does not 

exceed 15.2 cm (6 in.). 

No gap between the tank 

shell and the secondary 

seal shall exceed 1.3 cm 

(1/2 in.). The cumulative 

length of all secondary 

seal gaps exceeding 0.32 

cm (1/8 in.) shall be not 

more than 5% of the 

circumference. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-4 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

External Floating Roof Tank Requirements (Fittings)

PR 1178 R.463 40CFR60 BAAQMD 

Access hatches, gauge float. 

wells shall be equipped with 

covers that are gasketed and 

bolted, with no visible gaps. 

Gauge hatch/sample wells shall 

be equipped with covers that are 

gasketed and bolted, with no 

visible gaps. 

Adjustable roof legs wells shall 

be equipped with gaskets or the 

legs shall be covered with VOC 

impervious socks whenever the 

roof is floating. 

Floating roof rim vents and 

vacuum breakers shall be 

gasketed and closed at all times 

except when the tank roof is 

floated off or landed on its leg 

supports. 

Unslotted guidepoles shall be 

equipped with gasketed covers at 

the end of the poles. The covers 

shall be closed at all times, with 

no visible gaps, except when 

sampling. 

Unslotted guidepole wells shall 

be equipped with gasketed 

sliding covers and flexible fabric 

sleeves or wipers. 

Slotted guidepoles shall be 

equipped with a gasketed cover, 

a pole wiper and a pole sleeve 

that extends into the liquid. 

All openings in the roof 

except 

Pressure-vacuum valves, 

shall provide a projection 

below the liquid surface to 

prevent belching, escape, 

or entrainment of organic 

liquid, and shall be 

equipped with a cover, seal 

or lid. The cover, seal, or 

lid shall at all times be in a 

closed position, with no 

visible gaps, except when 

the device or appurtenance 

is in use. 

Except for the pressure vacuum 

valves, all openings shall meet the 

following conditions: 

The opening shall provide a 

projection below the liquid surface 

to prevent belching of liquid and 

reduce escaping of organic vapors. 

The view ports and other openings, 

except floating roof legs, shall be 

equipped with a gasketed cover, 

seal or lid, which shall remain in a 

closed position at all times, except 

when the opening is in use. 

Effective 6/1/93, view ports and 

other openings, except floating 

roof legs shall be equipped with a 

gasketed cover, seal or lid. 

For inaccessible openings on 

internal floating roof tanks, there 

shall be no visible gaps as viewed 

from the fixed roof manway, 

except when the opening is in use. 

Pressure-vacuum valves shall be 

set to within 10% of the maximum 

allowable working pressure of the 

roof or at least 25 mm Hg (0.5 

psig) and shall be properly 

installed, maintained, and in good 

operating order and shall remain in 

a gas tight condition (10,000 ppm, 

as methane), above background, 

except when the operating pressure 

exceeds the valve set pressure. 

Solid sampling and gauge wells 

shall be equipped with a cover, 

seal or lid, which shall be in a 

closed position with no gap 

exceeding 0.32 cm (1/8 in.) except 

when in use. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-5 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

External Floating Roof Tank Requirements (Fittings cont'd)

PR 1178 R.463 40CFR60 BAAQMD 

Roof drains shall be equipped 

with a slotted membrane fabric 

that covers at least 90% of the 

Opening 

Roof drains shall be 

equipped with a slotted 

membrane fabric that 

covers at least 90% of the 

opening 

Subpart Ka 

Roof drains to be 

equipped with slotted 

fabric membranes 

covering at least 90% of 

the opening. 

Subpart Kb 

Roof drains to be 

equipped with slotted 

fabric membranes 

covering at least 90% of 

the opening. 

As of 6/1/2000, the well on an 

EFRT shall be equipped with the 

following: a sliding cover, well 

gasket, pole sleeve, pole wiper and 

an internal float and float wiper 

designed to minimize the gap 

between the float and the well, 

provided that the gap shall in no 

case exceed 1/2 in. or shall be 

equipped with a well gasket, a zero 

gap pole wiper seal and a pole 

sleeve that projects below the 

liquid surface. 

Any emergency roof drain shall be 

provided with a slotted membrane 

fabric cover, or equivalent, that 

covers at least 90% of the area of 

the opening. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-6 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Internal Floating Roof Tanks 

PR 1178 R.463 40CFR60 BAAQMD 

As of 7/1/2002: 

-same requirements for roof 

fittings as external floating roof 

tanks. 

-support columns and wells shall 

be equipped with sliding covers 

that are gasketed or with flexible 

fabric sleeves. 

As of 7/1/2003, tanks shall be in a 

vapor tight condition (500 ppm per 

Method 21). 

May have a single seal or 

primary/secondary seals. 

Tanks built or modified 

prior to June 1, 1984 

allowed 50%LEL in the 

vapor space, those built 

after this date may have 

only 30% LEL. 

All fittings and opening 

shall be gasketed and 

controlled. 

Subpart Ka 

Each opening in the cover 

except for automatic bleeder 

vents, rim space vents, stub 

drains and leg sleeves is to be 

equipped with a cover, seal, 

or lid which is to be 

maintained in a closed 

position at all times (i.e., no 

visible gap) except when the 

device is in actual use. 

Each opening in the cover 

except for automatic bleeder 

vents and the rim space vents 

is to provide a projection 

below the liquid surface. 

Subpart Kb 

May have single foam or 

liquid filled liquid mounted 

seal, a mechanical shoe seal 

or double seal of which the 

primary may be vapor 

mounted. 

Each opening in the cover 

except for automatic bleeder 

vents, rim space vents, stub 

drains and leg sleeves is to be 

equipped with a cover, seal, 

or lid which is to be 

maintained in a closed 

position at all times (i.e., no 

visible gap) except when the 

device is in actual use. 

Each opening in the cover 

except for automatic bleeder 

vents and the rim space vents 

is to provide a projection 

below the liquid surface 

The internal floating roof 

shall be either : 

(a) A liquid mounted 

primary seal, mounted in 

full contact with the 

liquid in the annular 

space b/w the tank shell 

and the floating roof or 

(b) A vapor mounted 

primary and secondary 

seal. 

Metallic shoe-type seals 

shall be installed so that 

one end of the shoe 

extends into the stored 

liquid and the other end 

extends a minimum 

vertical distance of 18 

inches above the stored 

liquid surface. 

For welded external 

floating roof tanks 

installed after 2/1/93, no 

gap b/w the tank shell and 

secondary seal shall 

exceed 1.5 mm (0.06 in.). 
Appendix E Final Staff Report 

Proposed Rule 1178 E-7 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Fixed Roof Tanks 

PR 1178 R.463 40CFR60 BAAQMD 

Control system shall have 98% 

efficiency by weight. 

Any tank gauging or sampling 

device on a tank vented to the 

vapor recovery system shall be 

equipped with a vapor-tight cover 

which shall be closed at all times 

except during gauging or sampling. 

The roof of such tank shall be 

properly maintained to be vapor 

tight (500 ppm), with no holes, 

tears or uncovered openings. 

After July 1, 2004, PVV's on fixed 

roof tanks shall be maintained in a 

vapor tight condition except when 

tank pressure exceeds 

recommended settings. 

The vapor recovery system 

shall have an efficiency of 

at least 95 percent by 

weight.

Any tank gauging or 

sampling device on a tank 

vented to the vapor recovery 

system shall be equipped 

with a vapor-tight cover 

which shall be closed at all 

times except during gauging 

or sampling. The roof of 

such tank shall be properly 

maintained to be vapor tight 

with no holes, tears or 

uncovered openings. 

All piping, valves and 

fittings shall be constructed 

and maintained in a vaportight condition (1,000 ppm), 

in accordance with 

requirements of other 

District rules for such 

equipment. 

Subpart Ka 

A vapor recovery system 

which collects all VOC 

vapors and gases discharged 

from the storage vessel, and a 

vapor return or disposal 

system which is designed to 

process such VOC vapors 

and gases so as to reduce 

their emission to the 

atmosphere by at least 95 

percent by weight. 

Subpart Kb 

A closed vent system and 

control device meeting the 

following specifications: 

(i) The closed vent system 

shall be designed to collect 

all VOC vapors and gases 

discharged from the storage 

vessel and operated with no 

detectable emissions as 

indicated by an instrument 

reading of less than 500 ppm 

above background and visual 

inspections 
Appendix E Final Staff Report 

Proposed Rule 1178 E-8 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Inspection and Maintenance Requirements 

PR 1178 R.463 40CFR60 BAAQMD 

Semiannual inspections of 

primary and secondary seals 

and each time the tank is 

emptied and degassed done 

by certified person. 

All piping, valves, pressurevacuum valves and other 

openings shall be inspected 

on an annual basis and each 

time the tank is emptied and 

degassed. 

All defects shall be repaired 

within 72 hours or prior to 

putting the tank back in 

service. 

Semiannual inspections of 

primary and secondary seals 

and each time the tank is 

emptied and degassed done 

by certified person 

All defects shall be repaired 

within 72 hours or prior to 

putting the tank back in 

service 

Subpart K

Records of products stored, 

period of storage and 

maximum vapor pressure of 

the liquid stored. 

Subpart Ka 

Records of products stored, 

period of storage and 

maximum vapor pressure of 

the liquid stored. 

Subpart Kb 

Measurements of gaps 

between the tank wall and the 

primary seal (seal gaps) shall 

be performed during the 

hydrostatic testing of the 

vessel or within 60 days of 

the initial fill with VOL and 

at least once every 5 years 

thereafter. 

Measurements of gaps 

between the tank wall and the 

secondary seal shall be 

performed within 60 days of 

the initial fill with VOL and 

at least once per year 

thereafter. 

Primary Seal 

Inspection 

For welded EFRTs with seals 

installed after 9/4/85 and 

welded IFRTs with seals 

installed after 2/1/93, the seal 

shall be inspected for 

compliance by the operator 

once every 10 years. 

After 12/1/93, once every 10 

years, for IFRTs. 

Once every 5 years for all 

other tanks. 

Secondary Seal 

Inspection 

For welded EFRTs with seals 

installed after 9/4/85 and 

welded IFRTs with seals 

installed after 2/1/93, the seal 

shall be inspected for 

compliance by the operator 

once every 10 years. 

After 12/1/93, once every 10 

years, for IFRTs. 

Annually for all other tanks. 

The primary and secondary 

seals of all IFRTs shall be 

visually inspected for holes, 

tears, or other openings in the 

seal fabric which allow the 

emission of organic vapors. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-9 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Record Keeping and Reporting 

PR 1178 R.463 40CFR60 BAAQMD 

Inspection reports filled out on 

District approved forms and 

mailed to the District within 5 

working days or 120 hours if 

violations are found. 

Records to be kept for 5 years 

Inspection reports filled out on 

District approved forms and 

mailed to the District within 5 

working days or 120 hours if 

violations are found. 

Records to be kept for 3 years 

Subpart Kb 

Inspection reports of floating 

roof tanks submitted within 30 

days. 

For fixed roof tanks vented to 

vapor recovery a report an 

operating plan shall be kept, 

indicating the parameter 

monitored. 

For fixed roofs vented to a 

flare or incinerator a report 

shall be submitted indicating 

any period of pilot flame out 

within 6 months of initial 

start-up and on a semi-annual 

basis thereafter 

Records to be kept for a 

minimum of 2 years. 

An accurate record of 

liquids stored and their 

true vapor pressure 

ranges of such liquids 

shall be maintained. 

For primary seals, 

certification of actual gap 

measurements shall be 

submitted upon 

installation of such 

primary seal, 

replacement of such seal 

or prior to installation of 

secondary seals, and at 

least every 5 years 

following such 

installation or 

replacement, unless the 

secondary seal is for: 

An Internal Floating 

Roof Tank (IFRT) or a 

welded floating roof tank 

installed after 9/4/85 (for 

External Floating Roof 

Tanks - EFRTs) and after 

2/1/93 (for IFRTs), 

respectively. Then it 

shall be done every 10 

years. 

For secondary seals, 

EFRT - Annual 

certification of gap 

measurement. Time 

interval between 

certification not to 

exceed 15 months. 

IFRT - At least once 

every 10 years. 
Appendix E Final Staff Report 

Proposed Rule 1178 E-10 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Test Methods 

PR 1178 R.463 40CFR60 BAAQMD 

For VOC leaks EPA Method 21 

Efficiency of a vapor recovery 

system shall be determined 

according to EPA Methods 25 

or 25A; District Method 25.1 or 

25.3. 

Vapor pressure determination 

of liquids stored determined by 

flash point (ASTM Method D93) and 10% evaporation 

(ASTM Method D86). 

For VOC leaks EPA Method 

21. 

Efficiency of a vapor recovery 

system shall be determined 

according to SCAQMD Test 

Method 501.1 for the 

determination of total organic 

compound emissions. EPA 

Methods 25 or 25A may be 

used, as applicable, in place of 

SCAQMD Test Method 25.1 

specified in Method 501.1. 

The Reid vapor pressure 

specified in paragraph (b)(3) 

and the Reid vapor pressure 

used in determining the true 

vapor pressure limit specified 

in paragraph (d)(5) shall be 

determined according to 

ASTM D-323-82 or California 

Code of Regulations, Title 13, 

Section 2297 

Subpart Ka 

The true vapor pressure of 

materials stored is determined 

using available data on typical 

Reid Vapor Pressure from API 

Bulletin 2517 and maximum 

expected storage temperature 

Subpart Kb 

Vapor Pressure of crude and 

distillates is determined from 

nomographs in API Bulletin 

2517 or ASTM Method 

D2879-83 or is calculated or 

measured by an equivalent 

method. 

For VOC leaks: EPA 

Method 21. 

RVP: Manual of 

Procedures; Vol. III, 

Lab. Method 13 

Analysis of Samples, 

Total Vapor Pressure: 

Vol. IV, Lab. Method 28 

Determination of 

Emissions: 

Manual of Procedures, 

Vol. IV, ST-4 

Vol. IV, ST-7 
Appendix E Final Staff Report 

Proposed Rule 1178 E-11 December 11, 2001 

Comparison of PR 1178 with Rule 463 and 40CFR60 K, Ka and Kb and BAAQMD 

Regulation 8, Rule 5 

Rule Exemptions 

PR 1178 R.463 40CFR60 BAAQMD 

1. Pressurized storage tanks 

designed to operate in excess 

of 15 psig without any 

emissions to the atmosphere 

under emergency conditions. 

2. Domed external floating roof 

tanks installed prior to 1/1/02 

shall be exempt from rim seal 

system and other doming 

requirements outlined in this 

rule. 

3. Facilities with an emissions 

cap equal to or less than 

40,000 pounds (20 tons) per 

year of VOC shall be exempt 

from the requirements of the 

rule. 

4. External floating roof tanks 

with permit conditions 

limiting the true vapor 

pressure of the stored organic 

liquids in the tanks to 3 psia or 

lower shall be exempt from 

the doming requirements of 

the rule. 

5. Portable Baker tanks storing 

liquids with true vapor 

pressure of between 0.1 and 

0.5 psia and equipped with 

carbon canisters meeting the 

50 ppmv outlet concentration 

shall be exempt from 

performance testing, provided 

the operator conducts periodic 

EPA Method 21 measurement 

to ensure the 50 ppmv system 

standard is maintained. 

Oil production tanks with a 

capacity of between 19,815 

gallons and 42,008 gallons, 

which have a properly 

maintained vapor-tight roof 

and are equipped with a 

pressure-vacuum valve, 

which is set to within 10% 

of the maximum allowable 

working pressure of the 

tank, are exempt from the 

control requirements of the 

rule when: 

1. The liquid contents do 

not comply with 

paragraph (b) only 

when heated for 

shipment, and such 

heating occurs for no 

more than 48 hrs. and 

not more than once in 

any 20-day period or

the tank has a monthly 

average throughput of 

no more than 30 barrels 

of oil per day and was 

constructed prior to 

6/1/84. 

2. Tanks being brought 

into compliance within 

the 72-hr period from 

the determination of 

non-compliance. 

Subpart K 

Storage vessels for petroleum 

or condensate stored, 

processed, and/or treated at a 

drilling and production 

facility prior to custody 

transfer. 

Subpart Ka 

Petroleum liquid storage 

vessels with a capacity of less 

than 420,000 gallons used for 

petroleum or condensate 

stored, processed, or treated 

prior to custody transfer is 

exempt from the 

requirements of this subpart. 

Subpart Kb 

1. Vessels at coke oven byproduct plants 

2. Pressure vessels 

designed to operate in 

excess of 204.9 kPa and 

without emissions to the 

atmosphere. 

3. Vessels permanently 

attached to mobile 

vehicles such as trucks, 

railcars, barges or ships. 

4. Vessels with a design 

capacity less than or 

equal to 1589.874 cubic 

meters (420,045 gallons) 

used for petroleum or 

condensate stored, 

processed, or treated 

prior to custody transfer. 

5. Vessels located at bulk 

storage plants. 

6. Storage vessels located 

at gasoline service 

stations. 

7. Vessels used to store 

beverage alcohol 

1. Underground 

gasoline storage 

tanks at gasoline 

dispensing facilities 

are exempt from this 

rule. 

2. The rule does not 

apply to tanks storing 

organic liquids with a 

true vapor pressure 

of less than or equal 

to 0.5 psia as 

determined by the 

test methods outlined 

in the rule.