South Coast Air Quality Management District 

Planning, Rule Development & Area Sources

Final Staff Report 

SOx RECLAIM 

 

Part 2 

Summary of 

Consultants’ Analyses 

November 2, 2010 

Deputy Executive Officer 

Elaine Chang, DrPH 

Assistant Deputy Executive Officer 

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

Planning and Rules Manager 

Joe Cassmassi 

Author 

Minh Pham, M.S., P.E., Air Quality Specialist 

Contributor 

Kevin Orellana, Air Quality Specialist 

 

Reviewers 

Gary Quinn, P.E., Program Supervisor 

Joe Cassmassi, Planning & Rule Manager 

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

William Wong, Principal Deputy District Counsel 
TABLE OF CONTENTS 

CHAPTER 1– REQUEST FOR PROPOSALS & CONTRACT AWARDS ......................................................... 3

1.1 REQUEST FOR PROPOSAL (RFP) ..................................................................................................................... 3

1.2 CONTRACT AWARDS ...................................................................................................................................... 4

CHAPTER 2 – NEXIDEA’S ANALYSIS FOR COKE CALCINER & SULFURIC ACID PLANT .................. 7

2.1 RECOMMENDED BARCT LEVELS .................................................................................................................. 7

2.2 CONTROL TECHNOLOGY & COSTS ................................................................................................................. 8

2.3 EMISSION REDUCTIONS & COST EFFECTIVENESS ........................................................................................ 10

2.4 PLOT SPACE ................................................................................................................................................. 11

2.5 PROJECT TIMING .......................................................................................................................................... 11

CHAPTER 3 – ETS’S ANALYSIS FOR GLASS MANUFACTURING PLANT ............................................... 12

3.1 RECOMMENDED BARCT LEVELS ................................................................................................................ 12

3.2 CONTROL TECHNOLOGY & COSTS ............................................................................................................... 13

3.3 EMISSION REDUCTIONS & COST EFFECTIVENESS ........................................................................................ 15

3.4 PLOT SPACE ................................................................................................................................................. 15

3.5 PROJECT TIMING .......................................................................................................................................... 16

CHAPTER 4 – ETS’S ANALYSIS FOR CEMENT PLANT ................................................................................ 17

4.1 RECOMMENDED BARCT LEVELS ................................................................................................................ 17

4.2 CONTROL TECHNOLOGY & COSTS ............................................................................................................... 18

4.3 EMISSION REDUCTIONS & COST EFFECTIVENESS ........................................................................................ 21

4.4 PLOT SPACE ................................................................................................................................................. 22

4.5 PROJECT TIMING .......................................................................................................................................... 22

CHAPTER 5 – ETS/AEC’S ANALYSIS FOR FLUID CATALYTIC CRACKING UNITS ............................. 23

5.1 RECOMMENDED BARCT LEVELS ................................................................................................................ 23

5.2 CONTROL TECHNOLOGY & COSTS ............................................................................................................... 24

5.2.1 Control Technology ............................................................................................................................. 24

5.2.2 Costs .................................................................................................................................................... 27

5.3 EMISSION REDUCTIONS & COST EFFECTIVENESS ........................................................................................ 30

14.4 PLOT SPACE ................................................................................................................................................. 31

5.5 PROJECT TIMING .......................................................................................................................................... 31

CHAPTER 6 – ETS/AEC’S ANALYSIS FOR SRU/TAIL GAS SYSTEMS ....................................................... 32

6.1 RECOMMENDED BARCT LEVELS ................................................................................................................ 32

6.2 CONTROL TECHNOLOGY & COSTS ............................................................................................................... 32

6.3 EMISSION REDUCTIONS & COST EFFECTIVENESS ........................................................................................ 35

6.4 PLOT SPACE ................................................................................................................................................. 36

6.5 PROJECT TIMING .......................................................................................................................................... 36

CHAPTER 7 – ETS/AEC’S ANALYSIS FOR REFINERY BOILERS/HEATERS ........................................... 37

7.1 RECOMMENDED BARCT LEVELS ................................................................................................................ 37

REFERENCES – PART 2 ........................................................................................................................................ 38

APPENDIX A – SUMMARY OF CONSULTANTS’ RECOMMENDED CONTROL TECHNOLOGY & 

COSTS ....................................................................................................................................................................... 39

APPENDIX B – CONSULTANTS’ BIOGRAPHIES ............................................................................................ 45
Final Staff Report – Part 2 Chapter 1 – Request for Proposals & Contract Awards 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 3 November 2, 2010 

NOTE 

Final Staff Report, Part 2, includes a summary of ETS, Inc./AEC’s analyses and 

NEXIDEA’s analyses in 2008-2009 time frame. In 2010, staff contracted Norton 

Engineering Consultants (NEC) to review the first set of consultants’ analyses, and 

conducted a cost effectiveness analysis based on NEC’s recommendations, which is 

described in Section 12.2, Chapter 12 of the Final Staff Report, Part 1. The nonconfidential reports of ETS, Inc./AEC, NEXIDEA and NEC are available for public 

information and are posted on the AQMD website. The biographies of the consultants 

Marshall Bell, Robert Kunz, John McKenna, and James Norton are included in Appendix 

B of this Final Staff Report, Part 2. 

Chapter 1– Request for Proposals & Contract Awards 

1.1 Request for Proposal (RFP) 

On July 11, 2008, the Governing Board approved a release of Request for Proposal (RFP) to 

obtain proposals from qualified contractors to conduct an engineering study on existing 

commercially viable control technologies to further reduce SOx emissions from RECLAIM 

facilities to assist staff in identifying Best Available Retrofit Control Technologies (BARCT) to 

be implemented within the 2011-2014 time frame which would help the Basin attain the PM2.5 

ambient air quality standards by the 2015 deadline. The project consisted of three (3) modules 

with a total budget of $375,000.00 as shown in Table 10-1: 1, 2

1. Module 1 was to seek an engineering evaluation and cost analysis assessment on SOx 

reducing additives used in fluid catalytic cracking units. 

2. Module 2 was to seek an engineering evaluation and cost analysis assessment on SOx control 

technologies for refinery fuel gas and sulfur recovery/tail gas treatment units. 

3. Module 3 was to seek an engineering evaluation and cost analysis assessment on wet/dry 

scrubbing technologies for seven categories of equipment identified in Part I of this report: 1) 

FCCUs, 2) refinery SRU/tail gas systems, 3) refinery heaters/boilers, 4) coke calciner, 5) 

sulfuric acid plant, 6) container glass melting furnaces, and 7) cement kilns & a coal fired 

boiler located at a cement manufacturing facility. 

 

1

 South Coast Air Quality Management District Board Meeting July 11, 2008, Agenda # 29, Report of RFPs and 

RFQs Scheduled for Release in July. July 11, 2008. 

2

 South Coast Air Quality Management District, Request for Proposal, RFP #P2009-01, Evaluation of Emission 

Control Technologies for Further Reducing Sulfur Oxides Emissions from Stationary Sources in the South Coast Air 

Quality Management District’s RECLAIM Program. July 11, 2008. 
Final Staff Report – Part 2 Chapter 1 – Request for Proposals & Contract Awards 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 4 November 2, 2010 

Table 1-1 

List of Modules and Estimated Budget for SOx RECLAIM RFP 

Project Modules Budget 

Module 1- FCCU DeSOx Additives $36 K 

Module 2 – Refinery SRU/Tail Gas and Fuel Gas Systems $124 K 

Module 3 – Wet/Dry Scrubbers for 

 FCCUs, SRU/Tail Gas Systems, Boilers/Heaters $133 K 

 Coke Calciner $14 K 

 Sulfuric Acid Mfg Plants (w or w/o Cesium) $24 K 

 Container Glass Melting Furnaces $14 K 

 Cement Plant (Kilns & Coal fired boiler) $15 K 

Total $360 K (+ $15 K for meetings) 

The contractor was asked to complete five specific tasks for each module (or submodule): 

 

1. Identify promising existing commercially viable SOx control technologies/manufacturers; 

2. Conduct field assessment and site-specific engineering evaluations; 

3. Perform independent costs and cost effectiveness analysis; 

4. Prepare reports describing the methodology, findings and recommendations; and 

5. Attend in person and give testimony at the AQMD Governing Board hearings for the 

proposed amended rule as expert witness if asked by staff. 

1.2 Contract Awards 

After receiving approval from the AQMD Governing Board in July, staff released the RFP and 

conducted an extensive 1-month outreach in accordance with the District’s Procurement Policy 

and Procedure. In addition, since this project is highly technical in nature, staff contacted 

eighteen (18) highly specialized contracting firms/contractors recommended by vendors and 

manufacturers of air pollution control equipment and the Western State Petroleum Association 

(WSPA). As a result of this effort, within a short time frame, staff received and accepted a total 

of six (6) technical proposals submitted by the contractors on August 15, 2008. 

A four member panel was convened to evaluate the proposals including: one AQMD Assistant 

Deputy Executive Officer from Planning, Rule Development, and Area Sources Division; one 

AQMD Supervisor of the Best Available Control Technology team; one AQMD Supervisor of 

the Refinery Team; and one representative from WSPA. The evaluation process completed in 

August and staff drafted a proposal to present to the Board. 

At the Board meeting on September 5, 2008, the Governing Board approved staff’s proposal and 

awarded the contracts to two consultants, ETS, Inc. and Nexidea, Inc., to conduct the study for 

this project at their bidding costs shown in Table 10-2. The total amount of awards provided for 
Final Staff Report – Part 2 Chapter 1 – Request for Proposals & Contract Awards 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 5 November 2, 2010 

this project was $334,860. 3, 4, 5 Note that no contract was awarded to any of the proposals to 

conduct the Module 1 evaluation. 

Table 1-2 

List of Contracting Firms and Awards 

Project Modules Consultant Firm Awards 

SRU/Tail Gas & Fuel Gas Systems ETS $123,933

Wet/dry scrubbers for FCCUs, SRU/tail gas, boilers/heaters ETS $130,107

Wet/dry scrubbers for glass melting furnaces ETS $13,910

Wet/dry scrubbers for kilns & coal fired boiler ETS $13,910

Attending meetings as requested by AQMD staff ETS $7,500

Total for ETS $289,360 

Wet/dry scrubbers for coke calciner (module 3-B) Nexidea $14,000

Wet/dry scrubbers for sulfuric acid plants Nexidea $24,000

Attending meetings as requested by AQMD staff Nexidea $7,500

Total for Nexidea $45,500 

Total $334,860 

Note: Since only one refinery voluntarily participated in the short-term testing with FCCU DeSOx additives, staff 

decided to conduct the analysis for Module 1 in-house. 

The consultants started the projects immediately after receiving the awards. First, the 

consultants and staff scheduled and conducted site visits at BP, Chevron, ConocoPhillips, 

Tesoro, Valero, ExxonMobil, California Portland Cement Corp., Owens Brockway, and Rhodia 

Inc. in September - October 2008. During these site visits, the consultants gathered all necessary 

technical information on equipment and operating conditions, discussed with the facilities on 

operational characteristics of the equipment, observed the physical layout of the equipment, as 

well as listened to any concerns or foreseen constraints provided by the refinery technical experts 

related to future prospective add-on control devices. 

After the site visits, the consultants conducted their own independent research, contacted the 

control manufacturers and vendors, gathered cost information, and performed their own 

independent engineering analysis on commercially available control technologies and cost 

effectiveness. In October 2008, the consultants developed the draft reports which were 

distributed to the affected facilities and AQMD staff for comments. 

 

3

 South Coast Air Quality Management District Board Meeting September 5, 2008, Agenda # 3, Execute Contract to 

Evaluate Emission Control Technologies for Further Reducing Sulfur Oxides Emissions from Stationary Sources in 

the SCAQMD SOx RECLAIM Program. September 5, 2008. 

4

 South Coast Air Quality Management District, Contract# C09104 with Nexidea, Inc., Evaluation of Emission 

Control Technologies for Further Reducing Sulfur Oxides Emissions from Stationary Sources in the SCAQMD’s 

RECLAIM Program. September 5, 2008. 

5

 South Coast Air Quality Management District, Contract# C09105 with ETS, Inc., Evaluation of Emission Control 

Technologies for Further Reducing Sulfur Oxides Emissions from Stationary Sources in the SCAQMD’s RECLAIM 

Program. September 5, 2008. 
Final Staff Report – Part 2 Chapter 1 – Request for Proposals & Contract Awards 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 6 November 2, 2010 

After addressing all comments received from the facilities, as well as AQMD staff, the 

consultants finalized their analyses and reports for coke calciner, cement kilns, coal fired boiler, 

glass furnaces, and sulfuric acid plant on December 16, 2008 as planned in the contracts. 

Because of the complexity associated with the refinery systems and extensive communications 

between the consultants and the refineries, the consultants finalized their engineering analyses 

for FCCUs, SRU/tail gas, and fuel gas treatment systems in April 20, 2009, four months after the 

anticipated dates specified in the contract. 

A summary of the consultants’ recommendations in these engineering studies are provided in 

Chapter 11 through Chapter 16. 
Final Staff Report – Part 2 Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid Plants 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 7 November 2, 2010 

Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid 

Plant 

Nexidea, Inc. (Marshall Bell) 6, 7 was awarded the contract to study the control technologies for a 

coke calciner and two sulfuric acid plants in the District (named as Facility A, B and C in the 

consultant’s reports). Nexidea Inc.’s analysis and results are summarized this chapter. 

2.1 Recommended BARCT Levels 

Nexidea’s final conclusions in this study are summarized below: 

• It is feasible and cost effective to reduce SOx emissions to a level of 5 ppmv using wet 

scrubbing with caustic solution from coke calciner and sulfuric acid plants. However, the 

consultant recommended the District to set BARCT at 10 ppmv due to process control 

related issues. For sulfuric acid plants, the consultant recommended a BARCT level of 0.14 

lbs per ton acid, and for the coke calciner, the consultant recommended a BARCT level of 

0.25 lbs per ton coke. Excerpts from the consultant’s study are presented below: 

“The results of the study show that simple caustic treating can cost effectively reduce 

SO2 emissions to less than 5 ppmv for the all of the units in the study; however, the 

recommended BARCT level is 10 ppmv due to control issues at near-zero SO2 levels. It 

is recommended that Facility B Acid Plant and Facility C Calciner add a caustic 

scrubber to meet the 10 ppmv SO2 level. Facility A Acid Plant already uses an SO2-

selective amine to reduce SO2 to 20 ppmv. That unit can be revamped at low cost to meet 

a 10 ppmv SO2 level, thus addition of a caustic treater to that unit is not recommended. 

Table 1 presents a summary of the key findings of this study. Recommended BARCT is 10 

ppmv SO2, limited by process control issues..... 

Table 1: Summary of Recommendations 

Equipment BARCT Level Emission 

Reductions 

Cost 

Effectiveness 

Facilities A 

and B 

0.14 lbs SOx/ton acid (10 ppmv) <0.1 tpd (A) 

1.1 tpd (B) 

$1.4K - $5.6K 

Facility C 0.25 lbs SOx/ton coke (10 ppmv) 1 tpd $2.5K - $5.0K ”

 

6 A biography of Mr. Marshall Bell is attached in Appendix II-B of this report. 

7 SOx RECLAIM Final Report – Wet/Dry Scrubbing Technology for Sulfuric Acid Plants and Coke Calciner, 

Nexidea Inc., December 2008. 
Final Staff Report - Part 2 Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid Plants 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 8 November 2, 2010 

2.2 Control Technology & Costs 

To arrive at the conclusions presented above, Nexidea, Inc. conducted a literature research on 

wet/dry scrubbing control technology, both regenerative and non-regenerative. The consultant 

contacted four (4) vendors identified in Part I of the Staff Report and listed below for basic 

sizing and cost information to achieve 5, 10, and 20 ppmv SOx. 

 

• Cansolv Technologies, Inc. 

• Monsanto Envirochem Systems (MECS) 

• Belco Technologies 

• Tri-Mer 

As stated in Nexidea’s report: 

 “All four companies were sent requests for basic sizing and cost information for gas 

treating facilities that can reduce SO2 emissions. Each was asked to supply designs to 

meet 5, 10 and 20 ppmv SO2 in the treated gas streams. Belco, Tri-Mer and MECS 

responded with proposals. Cansolv Technologies responded with a letter stating that 

their technology is not economically attractive as a polishing unit, and they will not bid 

on Facility B or coke calciner. They will support the necessary upgrades to Facility A’s 

Cansolv Unit to allow it to meet a 10-ppmv SO2 level.” 

All four vendors responded that they could achieve 5 ppmv SOx if all process variables are 

carefully controlled and monitored. Three out of four vendors provided sizing and cost 

information to achieve 5 ppmv SOx. All four vendors indicated that they could easily treat the 

existing gas streams from the sulfuric acid plants and the coke calciner to 10 ppmv, and all four 

vendors provided sizing and cost data for this scenario: 

“Both Sulfuric Acid Plants and the Coke Calciner start with relatively low levels of SO2 

in the current discharge streams: 20 to 145 ppmv. Treating down to 10 ppmv SO2 is 

easy and straightforward with caustic treating. Belco, Tri-Mer and MECS all state that 

they can provide designs that will achieve SO2 levels down to 1-2 ppmv with caustic 

treating for Facilities B and C. Cansolv can achieve 10 ppmv SO2 with minor upgrades 

to the Facility A Acid Plant, and believe that 5 ppmv is possible if all process variables 

are carefully controlled.” 

Accurate process control at all load changes is critical to achieve 5 ppmv SOx outlet 

concentration. The consultant recommended 10 ppmv as BARCT to provide the operators some 

room to respond to plant load changes and to reduce possible scaling of the absorber unit, usage 

of caustic, and load to the effluent treatment plant: 

“The recommended treatment level is 10 ppmv for all three facilities. The reason for this 

slightly higher value is that treating to 5 ppmv is essentially treating to zero. At this 

extremely low level, control over caustic injection becomes difficult. Refer to Figure 1, 

which shows caustic addition versus SO2 in the treated gas. Note that the caustic 

injection rate is given in gallons per hour. A very small change in caustic addition rate 
Final Staff Report - Part 2 Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid Plants 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 9 November 2, 2010 

has a large impact on SO2 level. Even if the caustic is diluted to 20%, the injection rate 

is still very small, and normal load changes in the units can make constant control 

difficult. Belco warns that control at <5 ppmv requires an increase in the pH of the 

caustic solution. As the pH rises, the tendency towards scaling the absorber tower and its 

internals increases, and the composition of makeup water to the unit must be carefully 

watched. If the pH is raised too high, it is possible to start absorbing CO2, which can 

produce a hard, insoluble sodium carbonate scale in the tower. Control at <5 ppmv 

almost certainly will result in over-injection of caustic, which is both wasteful and adds 

to the treating load in the effluent treatment plant. Control at 10 ppmv gives the operator 

more control room to respond to plant load changes without undue attention to the unit.” 

BELCO and Tri-Mer provided the consultant the inside battery limit (ISBL) equipment costs for 

caustic scrubbers, whereas MECS supplied the total installed equipment (TIC) for caustic 

scrubber. It should be noted that the costs for the caustic scrubbers were the same regardless of 

the SOx desired outlet concentrations (5, 10 or 20 ppmv). Cansolv supported the revamping 

costs of existing control at Facility A estimated by the contractor. 

The estimated installed equipment costs provided in the consultant report were listed in the table 

below included 1) a 20% location factor increase to account for the difference in labor costs 

between the U.S. Gulf Coast and the Los Angeles area; and 2) a 35% contingency factor increase 

to account for other outside battery limit costs that might be needed for the project (e.g. utility 

upgrade and upgrade for effluent treating system.) added to the base costs. 

“Table 1: Estimated Installed Equipment Costs 

 Facility A Facility B Facility C 

Belco $3,090,131 $6,579,231 $13,302,633 

Trimer $2,999,249 $13,316,664 $21,059,914 

MECS $4,043,137 $7,497,015 $16,826,926 

Cansolv $500,000 

The vendors provided the consultant the following information to estimate the operating costs of 

the equipment: 

• Electric power, kilo-watt 

• Makeup water, gallons per minute 

• Caustic solution (50% grade), gallons per hour 

• Waste water treating, gallons per hour 

• Operating/Maintenance man-power, # of people 

The major differences in the operating costs for the three desired outlet SOx concentrations 5, 

10, 20 ppmv were simply the costs of more caustic solution and increased effluent to the waste 

water treatment. 
Final Staff Report - Part 2 Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid Plants 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 10 November 2, 2010 

2.3 Emission Reductions & Cost Effectiveness 

The estimated emission reductions from the 2005 actual reported emissions8

 to the feasible levels 

(5, 10, and 20 ppmv) were presented in the table below from the consultant’s final report: 

“Table 3: Estimated Emissions Reductions 

TPD SO2 

Reduction 

Facility A @ 5 ppmv 0.050 

Facility A @ 10 ppmv 0.033 

Facility A @ 20 ppmv NA 

 

Facility B @ 5 ppmv 1.192 

Facility B @ 10 ppmv 1.149 

Facility B @ 20 ppmv 1.064 

 

Facility C @ 5 ppmv 1.122 

Facility C @ 10 ppmv 0.997 

Facility C @ 20 ppmv NA” 

The consultant estimated the following cost effectiveness numbers assuming a 25-year life of 

caustic scrubbers, 4% interest rate, and using a cost effectiveness equation provided by staff: 

“Table 2: Cost Effectiveness 

 Cansolv Tri-Mer Belco MECS 

Facility A @ 5 ppmv NA $16,682 $17,596 $18,675 

Facility A @ 10 ppmv $5,556 $24,906 $26,273 $27,892 

Facility A @ 20 ppmv NA NA NA NA 

 

Facility B @ 5 ppmv NA $2,158 $1,594 $1,458 

Facility B @ 10 ppmv NA $2,229 $1,644 $1,503 

Facility B @ 20 ppmv NA $2,388 $1,77 $1,605 

 

Facility C @ 5 ppmv NA $3,375 $2,469 $2,624 

Facility C @ 10 ppmv NA $3,768 $2,749 $2,923 

Facility C @ 20 ppmv NA $4,946 $3,589 $3,821 

 

8 The consultant indicated in his report that the following existing average SOx concentrations were provided which 

the consultant later used in his estimated emission reductions: 

“Facility A Acid Plant: 20 ppmv SOs 

 Facility B Acid Plant: 145 ppmv SO2 

Facility C Coke Calciner: 50 ppmv SO2 

.....the potential reduction in SO2 from Facility C based on the 50 ppmv level is higher than reported... 

suggests that ...this study may overstate the potential emission reduction from Facility C.” 

The consultant indicated that the current levels reported to the District “.....are in the 20 - 30 ppmv range”.
Final Staff Report - Part 2 Chapter 2 – Nexidea’s Analysis for Coke Calciner & Sulfuric Acid Plants 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 11 November 2, 2010 

2.4 Plot Space 

The spaces for caustic scrubbers and associated equipment (e.g. ID fan) provided by the vendors 

and estimated by the consultant were summarized below: 

 Facility A Facility B Facility C 

BELCO 15 ft L x 20 ft W 20 ft L x 25 ft W 30 ft L x 40 ft W 

Tri-Mer 18 ft L x 18 ft W 46 ft L x 28 ft W 70 ft L x 52 ft W 

MECS 20 ft L x 20 ft W 25 ft L x 25 ft W 30 ft L x 30 ft W 

Cansolv No additional change in plot space Not available Not available 

For Facility A, the consultant concluded that: 

“If the Cansolv Unit is revamped to meet a 10 ppmv treated gas SO2 concentration, the 

existing equipment will be reused in its current location and current plot space will be 

sufficient. If a caustic polishing system were to be required, the new unit would have to 

be located some distance away from the Acid Plant. This would make ducting of the gas 

steam very difficult, and result in a much larger ID fan, as well as a higher capital cost.” 

For Facility B, the consultant concluded that: 

“There appears to be sufficient plot space ..... to accommodate all three designs.” 

For Facility C, the consultant concluded that: 

“In all three designs, it appears that some existing equipment will have to be relocated to 

make room for a new scrubber system....... There appears to be sufficient plot space on 

the south and west sides of the cooling tower .... to accommodate the Belco and MECS 

designs, which use a single tower; however, space to locate the proposed Tri-Mer design 

is questionable.” 

In addition, the consultant provided several suggestions to reduce the footprint of the Tri-Mer 

scrubber should that becomes the choice for the facilities. 

2.5 Project Timing 

The consultant estimated that the total project time needed to install the new caustic scrubbers at 

Facility B and Facility C was about 24 – 30 calendar months, and to revamp the existing control 

system at Facility A was about 12 months. 
Final Staff Report – Part 2 Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 12 November 2, 2010 

Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

ETS, Inc. (John McKenna) 9, 10 was awarded the contract to study the control technologies for 

two container glass melting furnaces located at a container glass manufacturing facility in the 

District. ETS Inc.’s analysis and results are summarized in this chapter. 

3.1 Recommended BARCT Levels 

ETS, Inc.’s final conclusion in this study is that it is feasible and cost effective to reduce SOx 

emissions to a level of 5 ppmv or less using wet scrubbing with caustic solution for container 

glass melting furnaces. The consultant recommended the District to set BARCT at 0.0058 

lbs/ton glass pulled (or 99% control.) 

Excerpts from ETS Inc.’s study are presented below: 

“ETS has conducted a top down analysis of alternative commercially feasible control 

technologies for the control of SOx emissions from the glass plant. This analysis 

considered the technology which was found to be the most effective in terms of sulfur 

dioxide removal and which can potentially be installed or retrofitted at O-I. Four 

vendors (Manufacturer A, Manufacturer B, Manufacturer C, and Manufacturer D) 

submitted quotes and performance claims and one vendor (Manufacturer E) submitted a 

description of suggested process improvements on the existing system with a rough 

budgetary equipment cost. Given the higher removal efficiency (99%), the Manufacturer 

A wet scrubber was selected as BARCT for the glass furnaces. 

A cost-effectiveness determination was executed for the BARCT case and a summary of 

the results is provided in the following table: 

Summary of Recommendations 

Equipment BARCT Level BARCT 

Emission Level 

Emission 

Reductions 

CostEffectiveness 

OwensBrockway A, B 

& C CEMS 

99% control 

(≤1 ppmv) 

0.0058 lbs/ton 

glass pulled 0.19 tpd $ 5.0 K/ton SOx 

Note: Baseline SOx emissions used in calculations were from 2005 (SCAQMD database for the period 

from January 2005 – December 2005)” 

 

9 ETS, Inc. team in this project included Dr. John McKenna, John Mycock, Dr. James Turner, Christina Clark and 

Jeff Smith. (AEC Engineering Inc. was a subcontractor for ETS, Inc. in the refinery study discussed in Chapter 14 – 

Chapter 16. AEC Engineering Inc. was not subcontracted for the analyses for glass in Chapter 12 and cement in 

Chapter 13.) The consultants’ biographies are included in Appendix II-B of this report. 

10 SOx RECLAIM Study - Final Report – Module 3-D: Wet/Dry Scrubbing Technology for Container Glass 

Manufacturing Plant, ETS, Inc., December 16, 2008. 
Final Staff Report – Part 2 Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 13 November 2, 2010 

3.2 Control Technology & Costs 

To arrive at the conclusions presented above, ETS Inc. conducted a literature research on wet 

scrubbing (non-regenerative) and dry scrubbing control technologies. Sources for their literature 

research included Air Waste Management Association (AWMA), McIlvaine, U.S. EPA, 

Industrial Clean Air Companies (ICAC), Glass Manufacturing Industry Council, and the Council 

of Industrial Boilers Association (CIBA). ETS Inc. contacted seventeen (17) vendors in the field 

of wet/dry gas scrubbing. The following five (5) vendors responded to their request for 

information: 

• Tri-Mer 

• Monsanto Envirochem Systems (MECS) 

• McGill Clean Air Technologies 

• Dustex 

• PPC, Industries 

As stated in the ETS Inc.’s report: 

“These vendors were contacted and supplied with a request for a technical response to 

the RFP shown in Table 6. The vendors were asked to provide a Budgetary Equipment 

Cost and Estimated Annual Operating Cost at the following three levels of performance: 

1) Lowest achievable level of efficiency with guarantee 

2) Next lowest achievable level of efficiency with guarantee 

3) Most comfortable achievable efficiency with guarantee...” 

“Four vendors (Manufacturer A, Manufacturer B, Manufacturer C, and Manufacturer D) 

submitted quotes and performance claims, and one vendor (Manufacturer E) submitted a 

description of suggested process improvements on the existing system with a rough 

budgetary equipment cost.......” 

 Control Technology Efficiency SOx Outlet Conc. 

Manufacturer A wet scrubber with 50% NaOH 99% Less than 5 ppmv 

Manufacturer B wet scrubber with 25% NaOH 95% 5 ppmv 

Manufacturer C dry gas scrubber 90% 10 ppmv 

Manufacturer D wet scrubber with 20% NaOH 90% Less than 10 ppmv 

After carefully reviewing the information collected from the literature research and submitted by 

the vendors, ETS Inc. concluded: 

“Given the higher removal efficiency (99%), the Manufacturer A Wet Scrubber was 

selected as BARCT for the glass furnaces...”

Regarding vendors’ cost estimates, ETS Inc. indicated: 
Final Staff Report – Part 2 Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 14 November 2, 2010 

“.....they were asked to provide a budgetary cost estimate for the supply and installation 

of their equipment. The vendor was also requested to identify any utilities needed and 

their expected rate of usage. The vendor was also asked to identify the amount and type 

of waste generated by the process. If the vendor’s approach was to modify or retrofit 

existing hardware, he was requested to supply a cost estimate for those activities. For 

example, if the proposed approach was that of dry or wet injection upstream of the 

baghouse, the proposal should have included an estimate for all required equipment 

hardware, reagent storage vessels, reagent feed control instrumentation, engineering, 

construction and installation, etc., as well as pre-engineering costs such as site testing 

activities to locate the reagent injection site to optimize system performance with respect 

to SO2 control and reagent utilization.” 

The basis for equipment costs was different from each vendor (e.g. two vendors provided total 

installation costs including freight, and the other two provided just equipment costs without 

installation costs and freight.) The consultants applied their engineering knowledge and 

judgment to reconcile all vendors’ costs to the same basis. In addition, the consultants included 

specific costs to cover areas that had been identified by the subject facility in the District (e.g. 

costs were added to cover additional treatment of the waste stream from the scrubber & 

additional ducting to the space available at the facility.) 

ETS Inc. included the following categories in estimating the capital cost: 

“Demolition and Decommissioning 

Civil/Concrete 

Structural 

Equipment 

Piping & Mechanical 

Electrical & Controls 

Misc. Direct & Indirect Costs: 

Contractor overhead and misc. rentals 

Contractor field supervision 

Mobilization/Demobilization 

Overtime/productivity factor 

Freight/shipping 

Sales Tax 

Commissioning and operating spares 

Start-up/initial fill material 

On-site training/start-up assistance 

FEED engineering through detailed design 

Project management” 

ETS, Inc. included the following categories in estimating the annual operating and maintenance 

costs: 

“Annual Maintenance Costs 

Periodic Maintenance Costs 

Additional Operating Costs 

Utilities: 
Final Staff Report – Part 2 Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 15 November 2, 2010 

Natural Gas 

Electricity 

Water 

Wastewater 

Cooling Water 

Compressed Air 

Solid Waste Disposal ” 

3.3 Emission Reductions & Cost Effectiveness 

A summary of emission reductions, cost estimates, and cost effectiveness using 25-year life for a 

wet gas scrubber and 4% interest rate estimated by ETS, Inc. is shown below: 

“ 2005 Baseline Emissions 0.195 tpd 

 Emission Reductions 0.19 tpd (99% efficiency) 

 Equipment Costs $1.10 million 

 Capital Costs $1.90 million 

 Annual Operating Costs $0.44 million 

 Present Worth Value (25-year life) $8.80 million 

 Cost Effectiveness Factor $4,988 per ton SOx reduced ”

ETS, Inc. did not estimate emission reductions and cost effectiveness associated with other levels 

of control (95%, 90%). ETS, Inc. indicated that: 

“In considering a curve of cost-effectiveness versus level of control there are two 

considerations. Firstly, will the control device capital cost vary with improved efficiency 

and secondly, will the operating cost increase with increasing efficiency. Since the 

capital cost is driven largely by the gas volume and since the volume is essentially 

constant there is little if any change in the capital cost over the considered range of 

efficiencies. With respect to operating cost versus efficiency, in the case of sodium 

hydroxide, while the utilization does increase with increasing efficiency, the cost of the 

sodium hydroxide was low enough to minimize the impact of efficiency on cost. Thus the 

merit of plotting a curve of cost versus efficiency seemed of little value.” 

3.4 Plot Space 

Two vendors provided overall footprint (below) and two provided dimensions for individual 

components of the control systems. Manufacturer A estimated a footprint of 32 ft L x 10 ft W, 

and Manufacturer D estimated a footprint of 20 ft L x 20 ft W. In the analysis for available 

space, the consultant indicated that: 

“The plant has limited space available for additional equipment, approximately a 14’ x 20’ 

footprint between two existing scrubbers. In addition O-I personnel indicated that the 

height of any new equipment could not exceed 30 feet above the top of the existing 

scrubbing vessels. A request was made of O-I to provide us with dimensional information 

pertaining to available space for the Manufacturer A equipment footprint. They stated that 
Final Staff Report – Part 2 Chapter 3 – ETS’s Analysis for Glass Manufacturing Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 16 November 2, 2010 

there is space available. Horizontal distance is 63’ depending on the location of the ducting 

out of the pieces of equipment. This does not take into account the vertical distance which 

will depend on location of entry to the stream.” 

3.5 Project Timing 

The consultant estimated that startup of the control equipment could occur 12 months after the 

project begins. 
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 17 November 2, 2010 

Chapter 4 – ETS’s Analysis for Cement Plant 

ETS, Inc. (John McKenna) 11, 12 was awarded the contract to study the control technologies for 

two cement kilns and a coal-fired boiler located at California Portland Cement Co. (CPCC). 

ETS Inc.’s analysis and results are summarized in this chapter. 

4.1 Recommended BARCT Levels 

ETS, Inc.’s final conclusion in this study is that it is feasible and cost effective to reduce SOx 

emissions to a level of 5 ppmv or less using wet scrubbing with caustic solution for two cement 

kilns and a coal-fired boiler. The consultant recommended the District to set BARCT at 0.03 

lbs/ton clinker (or 95% control efficiency) for the two cement kilns, and 95% control efficiency 

for the coal fired boiler. 

Excerpts from ETS Inc.’s study are presented below: 

“ETS has conducted a top down analysis of alternative commercially feasible control 

technologies for the control of SOx emissions from the cement plant. This analysis 

considered the technology which was found to be the most effective in terms of sulfur 

dioxide removal and which can potentially be installed or retrofitted at CPCC. In the case 

of the two kilns, three vendors (Manufacturer A, Manufacturer B, and Manufacturer C) 

submitted quotes and performance claims. Given the higher removal efficiency (95%), the 

Manufacturer B CaCO3 Scrubber was selected as BARCT for the kilns. 

Similarly top down analysis was done for the coal-fired fluidized bed boiler emission 

control at the cement plant. Four vendors (Manufacturer A, Manufacturer B, 

Manufacturer C, and Manufacturer D) submitted quotes and performance claims. Given 

the 95% removal efficiency, both the Manufacturer D Venturi Reactor & the Manufacturer 

B CaCO3 Scrubber can be considered BARCT for the coal-fired fluidized bed boiler. 

Cost-effectiveness determinations were executed for the BARCT cases and a summary of 

the results are provided in the following table. 

 

11 ETS, Inc. team in this project included Dr. John McKenna, John Mycock, Dr. James Turner, Christina Clark and 

Jeff Smith. (AEC Engineering Inc. was a subcontractor for ETS, Inc. in the refinery study discussed in Chapter 14 – 

Chapter 16. AEC Engineering Inc. was not subcontracted for the analyses for glass in Chapter 12 and cement in 

Chapter 13.) 

12 SOx RECLAIM Study - Final Report – Module 3-E: Wet/Dry Scrubbing Technology for Cement Kilns and CoalFired Fluidized Bed Boiler, ETS, Inc., December 16, 2008. 
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 18 November 2, 2010 

Summary of Recommendations 

Equipment BARCT Level BARCT Emission Level Emission 

Reductions 

Cost 

Effectiveness 

Kilns 95% control (≤2 ppmv) 0.03 lbs SOx/ton clinker 0.25 tpd SOx $18.9 K/ton SOx 

Coal-Fired 

Boiler 95% control (≤5 ppmv) --- 0.36 tpd SOx $ 3.8 K/ton SOx 

Note: Baseline SOx emissions used in calculations were from 2005 (SCAQMD database for the period from 

January 2005 – December 2005)”

4.2 Control Technology & Costs 

To arrive at the conclusions presented above, ETS Inc. conducted an independent literature 

research on wet scrubbing (non-regenerative) and dry scrubbing control technologies. Sources 

for their literature research included Air Waste Management Association (AWMA), McIlvaine 

Co., U.S. EPA, Industrial Clean Air Companies (ICAC), Portland Cement Association (PCA), 

and Northeast States for Coordinated Air Use Management (NESCAUM). ETS, Inc. research 

confirmed the information provided by staff in Part I of Staff Report that scrubbing technology 

had been used to control SOx for existing as well as new cement kilns and coal fired boilers. 

After the literature research, ETS Inc. contacted and asked sixteen (16) vendors in the field of 

wet/dry gas scrubbing to provide a budgetary equipment cost and estimated annual operating 

cost at the following three levels of performance: 

1) Lowest achievable level of efficiency with guarantee 

2) Next lowest achievable level of efficiency with guarantee, and 

3) Most comfortable achievable efficiency with guarantee 

For the vendors to size and estimate the costs associated with the control device, ETS, Inc. 

provided the vendors some of the following critical operational parameters: 

 Kilns Coal-Fired Boiler 

Gas Flow Rate 170,000 – 200,000 acfm 60,000 acfm 

Temperature 275 o

F 300 oF 

Inlet SOx Concentration 5 ppmv – 25 ppmv 13, 14 100 ppmv 13

Combustion fuel Coal, coke, oil, nat gas, and used tires Coal 

Raw feed material Limestone, silica, and clay 

 

13 ETS, Inc. reviewed several RATA tests for the two kilns and the cogen, and in addition, conducted a statistical 

analysis on the 2005 and 2008 CEMS data for the two kilns, and the 2001 CEMS data for the cogen, and determined 

that a range of SOx concentrations between 5 ppmv – 25 ppmv would reflect a reasonable range of SOx 

concentrations from the two kilns, and approximately 100 ppmv would reflect a reasonable range of SOx 

concentration from the coal-fired boiler. These ranges of concentrations were provided to the vendors for quotes 

and cost estimates. 

14 ETS, Inc. reported that “In general, the vendors questioned the low SO2 levels, stating that 200-400 ppm was 

more typical of long dry kiln operations. Several also indicated that before guaranteeing performance level, they 

would require pilot testing to confirm design information and to optimize operational parameters.”
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 19 November 2, 2010 

The following four (4) vendors responded to ETS, Inc.’s request of information: 

• Dustex 

• BoldEco 

• Monsanto Envirochem Systems (MECS) 

• Solios 

Three vendors proposed SOx emission control, submitted quotes, and performance claims for the 

cement kilns: 

 

• The first vendor (Vendor C) proposed wet scrubbers using 20% NaOH solution to 

achieve 90% guaranteed control for the two kilns 

• The second vendor (Vendor A) proposed a hybrid technology, a dry fluid bed scrubber 

(reaction tower) following by a pulse jet fabric filter, using hydrated lime (Ca(OH)2) as 

absorbent reagent to achieve 90% guaranteed reduction for SOx 

• The third vendor (Vendor B) proposed two different approaches for emission control: 

─ a moving bed reactor where the gas is contacted and absorbed on a bed of 

limestone granules (CaCO3) to achieve 95% reduction ; and 

─ a hybrid technology including a reactor and a polished fabric filter using hydrated 

lime (Ca(OH)2) as absorbent reagent to achieve 85% reduction 

Vendor Control Technology Control 

Efficiency 

SOx Outlet 

Concentration 

A Hybrid (reactor/scrubber/pulse-jet filter) using Ca(OH)2 90% < 5 ppmv 

B Hybrid (reactor/scrubber/pulse-jet filter) using Ca(OH)2 85% < 5 ppmv 

B Dry scrubber/reactor using limestone CaCO3 95% < 5 ppmv 

C Wet scrubber using NaOH 90% < 10 ppmv 

Four vendors proposed SOx emission control, submitted quotes, and performance claims for the 

coal-fired boilers: 

• The first vendor (Manufacturer C) proposed wet scrubbers using NaOH solution to 

achieve 90% guaranteed control (<10 ppmv SOx) 

• The second vendor (Vendor A) proposed a hybrid technology, a dry fluid bed scrubber 

(reaction tower) following by a pulse jet fabric filter, using hydrated lime (Ca(OH)2) as 

absorbent reagent to achieve 90% guaranteed reduction for SOx 

• The third vendor (Vendor B) proposed two different approaches for emission control: 

─ a moving bed reactor where the gas is contacted and absorbed on a bed of 

limestone granules (CaCO3) to achieve 95% reduction ; and 

─ a hybrid technology including a reactor and a polished fabric filter using hydrated 

lime (Ca(OH)2) as absorbent reagent to achieve 80% reduction 
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 20 November 2, 2010 

• The fourth vendor (Vendor D) proposed a dry injection system utilizing a venturi reactor 

and sodium bicarbonate (NaHCO3) to achieve 95% removal efficiency. 

Vendor Control Technology Control 

Efficiency 

SOx Outlet 

Concentration 

A Hybrid (reactor/scrubber/pulse-jet filter) using Ca(OH)2 90% < 5 ppmv 

B Hybrid (reactor/scrubber/pulse-jet filter) using Ca(OH)2 80% < 5 ppmv 

B Dry scrubber/reactor using limestone CaCO3 95% < 5 ppmv 

C Wet scrubber using NaOH 90% < 10 ppmv 

D Venturi reactor using NaHCO3 95% < 5ppmv 

After carefully reviewing all the information collected from the literature research and submitted 

by the vendors, ETS Inc. concluded: 

“Given the higher removal efficiency (95%), the Manufacturer B Dry Scrubber was 

selected as BARCT for the kilns.” 

“Given the 95% removal efficiency, both the Manufacturer D Venturi Reactor & the 

Manufacturer B Scrubber can be considered BARCT for the coal-fired fluidized bed 

boiler.” 

Regarding vendors’ cost estimates, ETS Inc. indicated: 

“.....they were asked to provide a budgetary cost estimate for the supply and installation 

of their equipment. The vendor was also requested to identify any utilities needed and 

their expected rate of usage. The vendor was also asked to identify the amount and type 

of waste generated by the process. If the vendor’s approach was to modify or retrofit 

existing hardware, he was requested to supply a cost estimate for those activities. For 

example, if the proposed approach was that of dry or wet injection upstream of the 

baghouse, the proposal should have included an estimate for all required equipment 

hardware, reagent storage vessels, reagent feed control instrumentation, engineering, 

construction and installation, etc., as well as pre-engineering costs such as site testing 

activities to locate the reagent injection site to optimize system performance with respect 

to SO2 control and reagent utilization.” 

The basis for equipment costs was different from each vendor. ETS, Inc. applied their 

engineering knowledge and judgment to reconcile all vendors’ costs to the same basis. 

Regarding the capital costs, ETS Inc. included the following categories in estimating the costs: 

“Demolition and Decommissioning 

Civil/Concrete 

Structural 

Equipment 

Piping & Mechanical 

Electrical & Controls 

Misc. Direct & Indirect Costs: 

Contractor overhead and misc. rentals 
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 21 November 2, 2010 

Contractor field supervision 

Mobilization/Demobilization 

Overtime/productivity factor 

Freight/shipping 

Sales Tax 

Commissioning and operating spares 

Start-up/initial fill material 

On-site training/start-up assistance 

FEED engineering through detailed design 

Project management” 

ETS, Inc. included the following categories in estimating the annual operating and maintenance 

costs: 

“Annual Maintenance Costs 

Periodic Maintenance Costs 

Additional Operating Costs 

Utilities: 

Natural Gas 

Electricity 

Water 

Wastewater 

Cooling Water 

Compressed Air 

Solid Waste Disposal” 

A list of assumptions used by ETS, Inc. for cost estimation was summarized by ETS, Inc. in 

Table 11 of the final report. 

4.3 Emission Reductions & Cost Effectiveness 

A summary of emission reductions, cost estimates, and cost effectiveness using 25-year life for a 

wet gas scrubber and 4% interest rate estimated by ETS, Inc. is shown below: 

 Two Scrubbers 

for Two Kilns 

One Scrubber for a 

Coal-Fired Boiler 

2005 Baseline Emissions tpd 0.27 0.38(if operated) 

Emission Reductions tpd 0.25 0.36(if operated) 

Equipment Costs $ million 16.6 4.7 

Capital Costs $ million 19.6 6.1 

Annual Operating Costs $ million 1.5 0.39 

Present Worth Value (25-year life) $ million 43.7 12.6 

Cost Effectiveness Factor $ per ton 18,893 3,818 

ETS, Inc. did not estimate emission reductions and cost effectiveness associated with other levels 

of control (90% or 80%). ETS, Inc. indicated that: 
Final Staff Report – Part 2 Chapter 4 – ETS’s Analysis for Cement Plant 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 22 November 2, 2010 

“In considering a curve of cost-effectiveness versus level of control there are two 

considerations. Firstly, will the control device capital cost vary with improved efficiency 

and secondly, will the operating cost increase with increasing efficiency. Since the 

capital cost is driven largely by the gas volume and since the volume is essentially 

constant there is little if any change in the capital cost over the considered range of 

efficiencies. With respect to operating cost versus efficiency, in the case of limestone, 

while the utilization does increase with increasing efficiency, the cost of the limestone 

was low enough to minimize the impact of efficiency on cost. Thus the merit of plotting a 

curve of cost versus efficiency seemed of little value.” 

4.4 Plot Space 

The plot space needed for each hybrid dry limestone scrubber located upstream of the existing 

baghouse of the Portland cement kiln was estimated to be approximately 50 ft L x 40 ft W. ETS, 

Inc. conclusion on plot space availability was as follow: 

“With the exception of moving some existing coal piles, there appears to be no limitation 

on available space for prospective equipment for additional SO2 control on the two 

cement kilns. If necessary, the existing baghouses could be considered for technology 

approaches (such as spray drying) requiring a filter collector after the reaction vessel. 

In this scenario the baghouse would serve the dual purpose of particulate control and the 

dust cake (on the bags) would provide an additional site for the reaction of the reagent 

with the SOx.” 

The plot space needed for the dry scrubber located upstream of the existing baghouse of the 

COGEN coal fired boiler was estimated to be approximately 10 ft L x 10 ft W. ETS, Inc. 

conclusion on plot space availability was as follow: 

 “......there appears to be no limited space for prospective equipment for additional SO2

removal on the COGEN. In addition, if the physical integrity of the existing pulse jet 

baghouse is sound, it could probably be utilized in conjunction with some of the dry or 

semi-dry scrubbing technologies. This could be accomplished by replacing any 

malfunctioning components such as valves, timers, dampers, etc., and replacing the 

existing bag set with high efficiency PTFE membrane bags.” 

4.5 Project Timing 

The consultant estimated that startup of the control equipment could occur 24 months after the 

project begins for both the cement kilns as well as the coal fired boiler. 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 23 November 2, 2010 

Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

ETS, Inc. (John McKenna) 15,16 was awarded the contract to study the control technologies 

(wet/dry scrubbers) for FCCUs located at six refineries in the District. ETS, Inc. subcontracted 

a part of the study to AEC Engineering Inc.17 The ETS/AEC’s analysis and results for FCCUs 

are summarized in this chapter. 

5.1 Recommended BARCT Levels 

ETS, Inc.’s final conclusion in this study is that it is feasible and cost effective to reduce SOx 

emissions to a level of 5 ppmv or less using wet scrubbing with caustic solution for six refineries 

in the District. ETS’s recommended the District to set BARCT at 5 ppmv, approximately 2.32 

lbs/thousand barrels feed, or 87% control, averaging across six FCCUs in the District. ETS 

Inc. estimated total emission reductions from the 2005 baseline were 3.07 tpd at an average cost 

effectiveness of $24.6 K per ton SOx reduced. 18,19

Excerpts from ETS Inc.’s study are presented below: 

“The final estimates of SOx reductions for the Module 3A BARCT-designated measures are 

tabulated below: 

Module 3A Forecasted SOx Reductions (tons/day) by Refinery

Refinery: 1 2 3 4 5 6 Total 

Equipment Type FCCU 0.58 0.19 0.28 0.20 0.87 0.94 3.07 

The following table gives a summary of the Module 3A cost effectiveness ratios by refinery 

following implementation of the respective measures selected by ETS/AEC: 

Module 3A Cost Effectiveness ($/ton of SOx) by Refinery

Refinery: 1 2 3 4 5 6 Avg. for All

Equipment Type FCCU $14.4k $76.2k $36.6k $42.1k $11.6k $12.8k $24.6k 

 

15 ETS, Inc. team in this project included John McKenna, Ph.D., Robert Kunz, Ph.D., P.E., James Turner, Ph.D., 

Christina Clark and Jeff Smith. The consultants’ biographies are attached in Appendix II-B of this report. 

16 SOx RECLAIM Study - Final Report – Module 3-A: Wet/Dry Scrubbing Technology for Refinery Fluid 

Catalytic Cracking Units (FCCUs), Refinery Boilers/Heaters, and Refinery Sulfur Recovery Units (SRUs) and Tail 

Gas Treatment Processes, AEC Engineering Inc./ETS, Inc., April 20, 2009. 

17 AEC Engineering, Inc. team in this project included Tav Heistand, P.E., Kristie Williams, P.E., Jason Sowards, 

Jesse Pikturna, Ph.D., and Britton Miller, P.E.

18 The estimated emission reductions 3.07 tpd were the reductions calculated from the 2005 baseline described in 

Part 1 of the Staff Report for all six FCCUs in the District. Note that this 3.07 tpd estimated reductions from 

ETS/AEC was not the same as the RTC reductions estimated in Staff Report for FCCUs. 

19 The cost effectiveness of $24.6 K is an average for five refineries. One refinery in the District already installed 

and has operated a wet gas scrubber to meet the particulate emission standards in Rule 1105.1, and this gas scrubber 

also meet the limeit of 5 ppmv proposed by ETS/AEC. 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 24 November 2, 2010 

5.2 Control Technology & Costs 

5.2.1 Control Technology 

‘To arrive at the conclusions presented above, ETS Inc. and AEC Engineering Inc. conducted an 

independent literature research on wet and dry scrubbing technologies including nonregenerative, regenerative, and sea water. After that, ETS/AEC contacted vendors for feasibility 

and cost information. As indicated by ETS/AEC: 

“Insofar as the wet and dry gas scrubbing technologies are concerned, information 

provided by SCAQMD was very helpful in identifying some of the vendors that were 

considered in this study. Contact was made with all vendors listed in the SCAQMD 

preliminary report and a number of vendors that were not listed. After initial discussions 

with vendors, careful reviews of various resources were conducted: literature provided 

by vendors; the April 2008 Preliminary Draft Staff Report; in-house files; public domain 

articles and reports; and conversations with industry experts. At that point, five different 

technology providers were selected for detailed analysis of installation and operation 

economics....” 

The technologies and vendors that ETS/AEC concentrated for further analysis (e.g. costs) for 

FCCUs were: 

• BELCO (non-regenerative wet gas scrubber) 

• MECS (non-regenerative wet gas scrubber) 

• Hamon (dry scrubber) 

• Alstom (sea water scrubber) 

Regarding BELCO technology, ETS/AEC stated that: 

“BELCO (DuPont) has more than 65 EDV wet scrubbing systems in refineries, at least 61 

of which are in FCCU applications and 156 EDV 20 wet scrubbing systems in other 

applications. BELCO also has examples of EDV applications for SRU/TGTU and refinery 

boilers and heaters (DuPont Power Point Presentation, 2008). In a letter sent to ETS from 

Nick Confuerto, Vice President, Technology, Sales & Marketing of BELCO, it was 

confirmed that the guaranteed SOx outlet concentration based on the refinery-specific 

information provided would be 5 ppmv. The EDV utilizes a Purge Treatment System to 

decrease the COD 21 and suspended solid content of the effluent. A clarifier is used to 

collect the solids and then they are filter-pressed and disposed. The oxidation is facilitated 

 

20 EDV® is a trademark wet gas scrubber manufactured and supplied by BELCO (Dupont). 

21 COD stands for Chemical Oxygen Demand, a commonly used measurement for water quality. It measures the 

capacity of water to consume oxygen during the decomposition of organic matter and the oxidation of inorganic 

chemicals such as ammonia and nitrite. It is an indirect measurement of the organic compounds (microorganisms) 

that survive in the waste water samples. 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 25 November 2, 2010 

in a tower with air forced through the effluent to convert all sulfites to sulfates. After these 

two steps the effluent is safely discharged to the waste water treatment plant.” 

Regarding MECS technology, ETS/AEC stated that: 

“....MECS developed their DynaWave technology in the 1970s and has over 300 

installations worldwide (Kixmiller, 2008). Specific examples are two Sinclair oil refineries 

in Wyoming. According to a published paper titled, “DynaWave Wet Gas Scrubbing: A 

New Alternative for Claus Unit Tail Gas Clean-Up”, written by Steven F. Meyer, Ed Juno, 

Nick Watts, and Cristina Kulczycki, each refinery installed a DynaWave scrubber for 

SRU/TGTU stack treatment. The results of stack testing was a 99.99% sulfur removal. 

The DynaWave mitigates the effluent COD by injecting air into the sump of the vessel in 

order to oxidize the sulfites. The sump is also designed to allow adequate retention time 

for the oxidation to take place. As a result, the effluent water can be discharged directly to 

the wastewater treatment plant, provided the COD levels are continuously monitored and 

maintained within an acceptable range. According to the paper, the COD at the Casper, 

WY refinery ranged between 50 and 150 mg/l.” 

Regarding dry scrubbing technology provided by Hamon, ETS/AEC stated that: 

“The dry scrubbing technology evaluated in this study is Hamon’s. It was evaluated for 

both FCCU and heater and boiler applications. According to information on its website, 

Hamon FGD technologies are installed in twenty countries and treat over 65,000 MW of 

power generation capacity. Hamon also has a long standing relationship with refineries 

world wide with over 100 ESP installations on FCCUs. There is no example of a dry 

scrubber installation in a refinery. However, the level of experience in FGD and general 

refinery applications is adequate to describe the technology as field demonstrated. In an 

email sent to AEC, a Hamon Research employee quoted a 90+% removal efficiency for 

streams with 300-400 ppmv SOx. Because flue gases in the South Coast refineries are 

typically below this range, the removal percentage is expected to be below 90% in most 

cases. Typically, it is governed by the SOx outlet concentration, which is not forecasted to 

fall below 10 ppmv on a guaranteed basis. Hence, the removal percentage for Hamon’s 

dry gas scrubber is application-specific in these refineries and generally will be below 

90%. One additional consideration for all types of dry scrubbers is the issue of solids 

handling. The effluent gas will have considerable particulate matter that must be removed. 

Therefore it is necessary to install some type of an ESP or baghouse downstream from the 

scrubber. The solids handling equipment will need to collect both dry particulate matter 

from the scrubber and particulate from the FCC. This introduces additional complexity 

with respect to available plot space and capital expenditure.” 

After several months of technical analysis and couple weeks visiting the refineries, ETS/AEC 

concluded that wet gas scrubbing was an aged-old technology which should be very familiar to 

all six refineries in the District: 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 26 November 2, 2010 

“One WGS vendor, Belco Technologies Corporation (BELCO), has provided a lengthy 

application list..., with contracts awarded on as many as sixty-one (61) FCCU units and 

two (2) fluid cokers. Total FCCU capacity treated by BELCO scrubbers is noted as 

3,228,700 bbl/day. The concept of using a WGS on an FCCU should be familiar to four 

(4) of the six (6) refining companies operating the Los Angeles, CA area since they are 

listed as customers employing BELCO WGS technology on the FCCUs at their other 

refineries........... 

Another vendor of WGS technology, Exxon (Now ExxonMobil), has also developed WGS 

technology. It is used in their own refineries and at others under license...... As of 1999, 

they cite a total of fourteen (14) such installations. One of the Exxon papers .... pictures 

a number of FCCU scrubbers located in tight spots because the required plot space was 

not otherwise available, including a photograph of a creative solution in which the 

scrubber is mounted on stilts above a road.” 

Regarding vendors’ guarantee, ETS/AEC indicated that BELCO and MECS were willing to 

provide guarantee on 5 ppmv: 

“BELCO has provided numerous wet gas scrubbers for FCCUs in the United States and 

on a worldwide basis. Based on that experience, BELCO has given a guarantee of 5 ppm 

SO2 from a wet scrubber if installed on any of the FCCUs in the District. MECS 

DynaWave, with at least three installations on FCCU regenerator flue gas, will also 

guarantee 5 ppmv SO2. BELCO has indicated that most of their units operate in the near 

zero ppm range, with the most recent performance test from one of these at a fraction of 

a ppm (corrected to 0% O2)....” 

In addition, ETS/AEC cited one full-scale installation that they were aware of: 

“.... The study team is aware of another full-scale wet gas scrubber operating on an 

FCCU in a petroleum refinery at an SO2 emission level of 5 ppmv or less on a long-term 

basis.” 

To be conservative in their BARCT recommendation, ETS/AEC recommended BARCT to be set 

at 5 ppmv. The vendors and ETS/AEC did not recommend lower levels just to avoid CEMS 

measurement uncertainty: 

..... the recommended BARCT level for fluid catalytic cracking unit (FCCU) SOx 

emissions is 5 ppmv on a dry basis. This is derived from an achievable concentration 

when employing wet gas scrubbing (WGS), a proven technology demonstrated in practice 

on this type of emission source. It is believed that a lower outlet concentration is indeed 

possible. However, a lower concentration may not be reliably measurable because of 

unavoidable accumulated error in the source test reference methods and/or the 

permissible tolerance in continuous emission monitoring system (CEMS) measurements.” 

 

“...After careful consideration of the various scrubbing approaches and review of the 

technical responses and guarantee statements offered by the suppliers of these 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 27 November 2, 2010 

technologies, it is the recommendation of the ETS team that non-regenerative wet 

scrubbing be considered on a purely technical basis as BARCT for the FCCUs, Refinery 

Boiler/Heaters, and SRU/TGTU processes under study in Module 3A, with an overall 

BARCT level of 5 ppmv.”

5.2.2 Costs 

To gather budgetary quotes from vendors on costs and sizing information, ETS/AEC provided 

the vendors important critical information (e.g. gas flow rate, inlet SOx concentration, flue gas 

temperature) for a generic scenario. ETS/AEC adjusted the vendors’ quotes information to 

match each refinery specific conditions. ETS/AEC claimed that their approach would ultimately 

generate cost information within +/- 40% range of the expected actual costs. As ETS/AEC 

stated that: 

“The methodology and techniques utilized during this project in the sizing of equipment 

for a new application ..... are exactly those used in any engineering endeavor. First, of 

course, we obtained a full understanding of how the existing system is configured and 

operates; those things are known by means of the site visit, underlying industry 

knowledge, interviews of refinery personnel, refinery-submitted data and drawings, etc. 

The second step was to conceptualize how the equipment under consideration is to be 

installed. This step also includes identifying the performance parameters to be achieved. 

In doing so, we quantified the expected ranges of service and efficiency, so that an 

appropriate over-design allowance could be applied (the purpose of which is to ensure 

that the performance objectives will reliably be met even if the underlying process is 

running at one extreme or another of its normal range). Next, all the pertinent 

information was communicated to the equipment representative, usually for pricing 

determination, but sometimes also to confirm the sizing exercise. In all cases, evaluating 

specific technology options required eventual coordination with the manufacturer or 

licensor to get verification of critical assumptions and/or conclusions. 

Since the study encompassed multiple facilities and systems with widely different process 

flows and arrangements, and because, furthermore, there were several optional 

technologies looked at for each installation, the total collection of potential measures 

was extraordinarily large. Thus, it was impossible—in the timeframe available—to 

address every one of the individual cases with a full set of vendor inquiries. Instead, the 

team made use of generic, but representative budgetary quotations and published cost 

studies for the various technologies. Each such “reference point” (i.e., package cost and 

performance data for a prescribed process operating condition) was then used as a basis 

for extrapolation to other locations and design conditions. For a specific application, 

the key sizing criterion (typically the process throughput—e.g., SCFM of gas) is 

determined or calculated from the relevant operational data. Then, to generate the 

probable capital purchase cost ($PC), that criterion value (V) is divided by the 

comparable numerical capacity (Cr) from the “reference point” package. Using the 

baseline capital cost ($BCr) for that “reference point”, the desired capital cost is 

mathematically calculated via a conventional power curve relationship: 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 28 November 2, 2010 

 $PC = $BCr x (V/Cr) ^ n 

where n is an appropriate exponent between .5 and 1.0 

This approach is commonly used in engineering studies, and has been widely described 

in reference books such as Marks Standard Handbook for Mechanical Engineers and 

Perry’s Chemical Engineers’ Handbook. For our studies, the exponent value, n, was 

normally assigned a value between 0.6 and 0.7, a range that historically has given good 

estimates for industrial equipment packages. 

In so far as the pertinent sizing criteria were concerned, they were compared to 

nameplate duties for other, similar units for rough verification purposes. Also, input was 

sought directly from the manufacturers’ representatives, as well as public domain 

literature and published case studies. In the end, the checking procedures employed by 

the team members helped us to achieve rough, budgetary purchase costs, knowing that 

any loss in precision in arriving at those costs would be adequately covered by the very 

broad overall cost ranges (i.e., +/- 40%) expected for the ultimate results.”

Regarding estimates for capital costs, ETS/AEC indicated that: 

“AEC worked as closely as possible with the technology suppliers to gather the direct 

capital cost estimates for this project. (Where available, too, we compiled net 

installation costs which had been reported by the manufacturers for “reference points”, 

as described in the preceding section. Those “turn-key” costs were used to check the 

built-up cost estimates assembled by the project team.) Also, we took advantage of our 

relevant and extensive corporate knowledge base for similar projects. Every valid 

method was employed to give the best possible output. (In addition, as mentioned in 

Section A, above, indirect costs for impacts to utilities and infrastructure were estimated 

and included.)....

...Owing to the fact that all the cost estimating tasks were conducted in a very 

preliminary, conceptual fashion, the overall accuracy of the capital cost determinations 

is no better than +/- 40%. Considerable engineering study would be required to refine 

the cost estimates and arrive at narrower accuracy ranges.” 

Regarding annual operating costs, ETS/AEC explained their approach as follows: 

“Unit rates for the principal cost-incurring utilities were requested from the refineries at 

the outset of the study. In several cases, explicit values were provided in response to the 

requests; those values were used as reported to us. For all other instances, generic 

estimates—obtained from other work by AEC at various U.S. refineries—of the unit rates 

were utilized... 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 29 November 2, 2010 

...The majority of the suggested control technologies or upgrades include the need not 

only for additional utilities but also raw materials, such as a scrubbing agent or catalyst. 

Costs for those items were estimated through consultation with a technology supplier or 

in-house expert. The appropriate third party resource or corporate engineer(s) based the 

quantity determinations on the specific characteristics of the technology under study. 

Once a quantity was determined, a local material cost was obtained for use in the 

calculations... 

...Early in the project, AEC had requested from the refineries the average hourly costs 

for various labor classifications on typical capital projects. When plant-specific values 

were not provided, we used generic labor rates that are intended to reflect average fullyburdened costs for jobs inside a South Coast refinery 

...The computation of chemical (such as NaOH) quantities used by the various measures, 

and the amounts of waste products generated by them, were very straightforward. In 

almost all instances, the manufacturers’ literature provided guidelines and/or explicit 

case studies. That information was used via direct “scale-up” multipliers, based on the 

key parameter(s) involved...” 

ETS/AEC applied their engineering knowledge and judgment to reconcile all vendors’ costs to 

the same basis. Regarding the capital costs, ETS Inc. included the following categories in 

estimating the costs: 

“Demolition and decommissioning 

Civil/concrete 

Structure 

Equipment 

Piping and Mechanical 

Electrical and controls 

Miscellaneous indirect costs include: 

Contractor overhead, typically 8 % of direct field labor (DFL) 

Contractor field supervision, typically 12 % of DFL 

Mobilization/demobilization, typically 10 % of DFL 

Overtime/productivity factor, typically 12 % of DFL 

Freight and shipping, typically 8 %, of materials 

Sales tax, typically 7 % of materials 

Commissioning and operating spares, typically 5 % of materials 

Startup/initial fill material, typically 2 % of materials 

On-site training/startup assistance, depends on project 

Front-end engineering design, depends on project size 

Project management, depends on project size 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 30 November 2, 2010 

Design development allowance, 10% of total 

Contingency, 25-40% applied against the bottom-line capital cost estimate” 

ETS, Inc. included the following categories in estimating the annual operating and maintenance 

costs: 

“Annual Maintenance Costs 

Periodic Maintenance Costs 

Additional Operating Costs 

Utilities: 

Natural Gas 

Electricity 

Water 

Wastewater 

Cooling Water 

Compressed Air 

Solid Waste Disposal” 

A list of assumptions used by ETS/AEC for cost estimation was summarized in Table 4-1 of the 

ETS/AEC’s final report for Module 3-A. 

5.3 Emission Reductions & Cost Effectiveness 

A summary of emission reductions, cost estimates, and cost effectiveness assuming 90% control 

(5ppmv), 25-year life for a wet gas scrubber, and 4% interest rate estimated by ETS/AEC is 

shown below: 

SOx Reductions (tons/day) for FCCUs by Refinery (5 ppmv)

Refinery: 1 2 3 4 5 6 Total 

Equipment FCCU 0.58 0.19 0.28 0.20 0.87 0.94 3.07 

Cost Effectiveness ($/ton of SOx) for FCCUs by Refinery (5 ppmv)

Refinery: 1 2 3 4 5 6 Avg. for All 

Equipment FCCU $14.4k $76.2k $36.6k $42.1k $11.6k $12.8k $24.6k 

In addition, ETS/AEC provided an estimate for the following emission reductions and cost 

effectiveness associated with the most stringent, but feasible level of control (98%) in Table A-3 

and A-4 of their final report: 

SOx Reductions (tons/day) for FCCUs by Refinery (98%)

Refinery: 1 2 3 4 5 6 Total 

Equipment FCCU 0.60 0.30 0.35 0.24 0.94 1.01 3.45 

Cost Effectiveness ($/ton of SOx) for FCCUs by Refinery (98%)

Refinery: 1 2 3 4 5 6 Avg. for All 

Equipment FCCU $14.0k $48.0k $29.5k $35.2k $10.7k $11.9k $21.5k 
Final Staff Report – Part 2 Chapter 5 – ETS/AEC’s Analysis for Fluid Catalytic Cracking Units 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 31 November 2, 2010 

Regarding the average cost effectiveness, ETS/AEC indicated that: 

“One refinery has already installed a wet gas scrubber on its FCCU regenerator.... the 

cost effectiveness ratio for this refinery was not included in any of the average cost 

effectiveness calculations.” 

14.4 Plot Space 

ETS/AEC conducted an analysis for plot space at the refineries to accommodate the wet gas 

scrubber and its associated equipment (e.g. additional fan, waste water handling system, plume 

mitigation system), presented their analysis in the confidential portion of the report, and 

concluded that space was available at all five refineries for additional control: 

“Wet gas scrubber equipment footprints and space requirements for the FCCUs and the 

SRU/TGTUs are shown in the confidential appendices for each refinery where measures 

have been selected. These specifications have been compared with the plot plans 

provided by the respective refineries, and where applicable, are presented in the costing 

workbooks.” 

5.5 Project Timing 

AEC/ETS estimated that startup of the control equipment could occur within 3 calendar years 

after the project begins: 

“ETS believes that it is conceivable that ....emission reduction ..... can be achieved from 

the refineries implementing the commercially available measures described in this 

project within a construction time frame of approximately 3 calendar years or less 

following the completion of study designs and engineering.” 
Final Staff Report – Part 2 Chapter 6 – ETS/AEC’s Analysis for Sulfur Recovery Unit/Tail Gas Systems 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 32 November 2, 2010 

Chapter 6 – ETS/AEC’s Analysis for SRU/Tail Gas Systems 

6.1 Recommended BARCT Levels 

Through the data provided to ETS/AEC by the refineries, there was one refinery regularly vented 

the flue gas to the atmosphere, and the remaining refineries treated or incinerated the tail gas 

from their SRU/TG systems. Because of this distinction in the refinery’s operations, ETS 

divided their recommendations for SRU/TG into two areas: the first recommendation is for the 

uncombusted tail gas: 

“For uncombusted tail gas, the limits of Subpart J (Ja), namely 10 ppm H2S and 300 

ppm reduced sulfur species (total of H2S, COS, and CS2), should continue to apply. 

Refineries should be encouraged to reduce emissions so as to be able to vent rather than 

having to combust SRU / TGTU tail gas.” 

The ETS’s second recommendation for the combusted tail gas is as follows: 

“For combusted / incinerated tail gas, 5 ppmv SOx @ 0% O2 should be defined as the 

overall BARCT level for all refineries, based on scrubbed flue gas, but permissible to 

achieve by whatever means possible. A level of 10 ppmv would allow a greater number 

of refineries to meet the overall BARCT level by the gas treatment methods of Module 2 

without having to install a wet gas scrubber (Module 3A)” 

6.2 Control Technology & Costs 

To arrive at the conclusions presented above, ETS Inc. and AEC Engineering Inc. conducted an 

independent literature research on wet and dry scrubbing technologies including nonregenerative and regenerative for Module 3A; and numerous technologies for Module 2 

including expansion of Claus process, sub-dewpoint process, selective oxidation catalyst, TG-10 

additives, and additional sulfur capture at the sulfur pit. After the literature search, ETS/AEC 

contacted vendors for feasibility and cost information. 

The five technologies and vendors that ETS/AEC concentrated for further analysis (e.g. costs) 

for SRU/TG systems were: 

• Lurgi (sub-dewpoint HydroSulfreen process) 

• EmeraChem Power LLC (selective oxidation catalyst) 

• Gas Spec (TG-10 additive) 

• Cansolv & BELCO (regenerative wet gas scrubber) 

• Tri-Mer (non-regenerative wet gas scrubber) 

For Lurgi Hydrosulfreen process, ETS/AEC stated that: 
Final Staff Report – Part 2 Chapter 6 – ETS/AEC’s Analysis for Sulfur Recovery Unit/Tail Gas Systems 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 33 November 2, 2010 

“The HydroSulfreen process is an improvement on Lurgi’s Sulfreen process. It adds a 

hydrolysis step to this process. There are over 45 Sulfreen processes in operation 

worldwide. In August of 2000, there were four HydroSulfreen plants licensed. 

The HydroSulfreen® process is typically used for treatment of tail gas from refineries. 

The effluent from an existing Claus plant is first treated in a hydrolysis reactor, where 

species such as SOx, CS2, and COS are hydrolyzed to form H2S. The effluent from the 

hydrolysis reactor is typically sent to the Sulfreen® process, which operates at 

temperatures lower than the dew point of sulfur. Operating the converters at these 

temperatures increases the conversion to elemental sulfur, thereby increasing the overall 

efficiency of the unit.” 

ETS/AEC estimated that the costs of conversion from normal Claus unit to HydroSulfreen were 

high and the cost effectiveness was in a range of $37,000 - $600,000 per ton of SOx reduced. 

This technology was not recommended by ETS/AEC at the final selection stage. 

Regarding EmeraChem Power LLC’s catalyst oxidation process, ETS/AEC stated that: 

“EmeraChem ESx catalyst can capture multiple sulfur species, including SO2, SO3, and 

H2S. In addition to sulfur capture, the catalyst will destroy CO, VOC, and Particulate 

Matter (PM10). These units are typically used to treat combustion exhaust gases from 

incinerators, heaters, turbines and boilers. 

EmeraChem does not appear to have its ESx technology installed as a stand-alone SOx

control technology at any refinery......EmeraChem has provided assurances that their 

technology works to reduce pollution in exhaust gases across many types of unit 

operations, including refinery processes, gas turbines, boilers, process heaters, and 

diesel engines.” 

EmeraChem platinum catalysts can be used to treat tail gas that has or has not been incinerated. 

The tail gas that has not been incinerated must be heated to the temperatures where the ESx 

catalyst is active (minimum at 600o

F). ETS/AEC estimated that the cost effectiveness for 

Emerachem catalysts was in a range of $10,000 - $60,000 per ton of SOx reduced. 

EmeraChem provided ETS/AEC a letter specifically stated the following performance guarantee: 

“EMx System Emission Concentration: 

 Parameter Percent Removal 

NOx at Catalyst Outlet (EMx) < 2.0 ppmvd 92% guaranteed 

CO at Catalyst Outlet < 3.0 ppmvd 98% guaranteed 

SO2 at System Outlet 3.85 ppmvd 98% guaranteed 

H2S at System Outlet 0 ppmvd 98% guaranteed 
Final Staff Report – Part 2 Chapter 6 – ETS/AEC’s Analysis for Sulfur Recovery Unit/Tail Gas Systems 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 34 November 2, 2010 

The catalyst warranty period is 5 years. Expected life of the catalysts is 10-15 years.” 

Regarding TG-10 additives, ETS/AEC stated that: 

“TG-10 can be added to tail gas treating amine systems. TG-10 is a proprietary amine 

mixture offered by INEOS Gas/Spec. It has been designed to be highly selective for H2S. 

INEOS Gas/Spec has published data, comparing the capabilities of TG-10 and MDEA in 

actual tail gas plants.......For many reasons similar to those in fuel gas treating, the 

effectiveness ratios for TG-10 can appear to be quite attractive.” 

ETS/AEC estimated that the cost effectiveness for TG-10 additives was between $2,000 and 

$3,000 per ton of SOx reduced, however the potential of emission reductions was quite small 

0.04 tpd - 0.07 tpd, and most of the refineries already used TG-10 in some fashion. Therefore, 

this measure was not recommended by ETS/AEC at the final selection stage. 

Regarding Cansolv and BELCO regenerative wet gas scrubbing technology, ETS/AEC stated 

that: 

 “Regenerative wet gas scrubbing was studied as a potential measure to reduce emissions 

from the SRU/TGTUs. Two manufacturers were considered for RWGS: BELCO’s 

Labsorb and Cansolv. Cansolv was chosen, in particular for SRU/TGTU stack 

treatment, because they had more experience with SRU/TGTU incinerator stack gas 

scrubbing.”

Regarding Tri-Mer non-regenerative wet gas scrubber, ETS/AEC stated that: 

“Non-regenerative wet gas scrubbing of the sulfur plant tail gas was also studied (TriMer’s Cloud Chamber Technology). These units are typically less expensive to install 

than a regenerative system, but they consume large volumes of water and produce waste 

water. However, they are very effective at reducing SOx emissions.”

Tri-Mer provided ETS/AEC a guaranteed letter specifically stated the inlet parameters (gas 

volume and temperature) provided to Tri-Mer and the following statement of guarantee: 

“With regard to the specifications provided to Tri-Mer by ETS Inc., based on the design 

conditions, Tri-Mer will guarantee ≤330 ppmv inlet SO2 to ≤1.0 ppmv outlet for SO2.” 

ETS/AEC indicated with confidence: 

“Guaranteed outlet SOx concentrations of 5 ppmv after scrubbing can be achieved, in 

the worst case at 95% SOx removal efficiency; in most cases, the required scrubbing 
Final Staff Report – Part 2 Chapter 6 – ETS/AEC’s Analysis for Sulfur Recovery Unit/Tail Gas Systems 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 35 November 2, 2010 

efficiency for a 5-ppmv SOx outlet is considerably less. BELCO has demonstrated 

experience in scrubbing the SOx from incinerated sulfur plant tail gas as well. 

Besides wet scrubbing technology, ETS/AEC also indicated that flue gas treating techniques 

(e.g. EmeraChem) can possibly bring down the SOx to a level of 5 ppmv – 10 ppmv: 

“.......it has been found possible in this study also to reduce SRU ppm SOx to the 

atmosphere by the gas treating techniques investigated. Those results are all below 10 

ppmv, and in many cases below 5 ppmv” 

To gather budgetary quotes from vendors on costs and sizing information, ETS/AEC provided 

the vendors important critical information (e.g. gas flow rate, inlet SOx concentration, flue gas 

temperature) for a generic scenario. ETS/AEC adjusted the vendors’ quotes information to 

match each refinery specific conditions. ETS/AEC claimed that their approach would ultimately 

generate cost information within +/- 40% range of the expected actual costs. Please refer to 

section 14.2 for further information on ETS/AEC’s approach. 

6.3 Emission Reductions & Cost Effectiveness 

For three refineries (Refinery #1, #3 and #4), ETS/AEC recommended to implement the control 

technologies described in Module 2 report. For these three refineries, ETS/AEC estimated the 

following emission reductions (estimated from the 2005 actual emissions) and cost effectiveness: 

SOx Reductions (tons/day) for SRU/TG by Refinery 

Refinery: 1 3 4 Total 

Equipment SRU/TG 0.13 0.15 0.04 0.31 

Cost Effectiveness ($/ton of SOx) for SRU/TG by Refinery 

Refinery: 1 3 4 Avg. for All 

Equipment SRU/TG $22.4k $12.9k $54.7k $21.9k 

 For the remaining three refineries (Refinery #2, #5 and #6), ETS/AEC recommended to 

implement wet gas scrubbers described in Module 3A report. For these three refineries, 

ETS/AEC’s recommendations for the emission reductions (estimated from the 2005 actual 

emissions) and cost effectiveness are as follows: 

SOx Reductions (tons/day) for SRU/TG by Refinery 

Refinery: 2 5 6 Total 

Equipment SRU/TG 0.17 0.06 0.29 0.52 

Cost Effectiveness ($/ton of SOx) for SRU/TG by Refinery 

Refinery: 2 5 6 Avg. for All 

Equipment SRU/TG $39.0k $123.2k $36.3k $46.8k 
Final Staff Report – Part 2 Chapter 6 – ETS/AEC’s Analysis for Sulfur Recovery Unit/Tail Gas Systems 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 36 November 2, 2010 

The overall estimates for emission reductions (estimated from the 2005 actual emission levels) 

and average cost effectiveness for six SRU/TG systems are as follows: 

SOx Reductions (tons/day) for SRU/TG by Refinery 

Refinery: 1 2 3 4 5 6 Total 

Equipment SRU/TG 0.13 0.17 0.15 0.04 0.06 0.29 0.83 

Cost Effectiveness ($/ton of SOx) for SRU/TG by Refinery 

Refinery: 1 2 3 4 5 6 Avg. for All 

Equipment SRU/TG $22.4k $39.0k $12.9k $54.7k $123k $36.3k $37.4k 

6.4 Plot Space 

With plot space information estimated directly by the vendors, ETS/AEC conducted an analysis 

for plot space at the refineries to accommodate the wet gas scrubber and its associated equipment 

(e.g. additional fan, waste water handling system, plume mitigation system). Their analysis was 

included in the confidential portion of the reports. ETS/AEC concluded that space was available 

at all refineries for this type of control: 

“Wet gas scrubber equipment footprints and space requirements for the FCCUs and the 

SRU/TGTUs are shown in the confidential appendices for each refinery where measures 

have been selected. These specifications have been compared with the plot plans 

provided by the respective refineries, and where applicable, are presented in the costing 

workbooks.” 

6.5 Project Timing 

AEC/ETS estimated that startup of the control equipment could occur within 3 calendar years 

after the project begins: 

“ETS believes that it is conceivable that ....emission reduction ..... can be achieved from 

the refineries implementing the commercially available measures described in this 

project within a construction time frame of approximately 3 calendar years or less 

following the completion of study designs and engineering.” 
Final Staff Report – Part 2 Chapter 7 – ETS/AEC’s Analysis for Refinery Boilers/Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 37 November 2, 2010 

Chapter 7 – ETS/AEC’s Analysis for Refinery Boilers/Heaters 

7.1 Recommended BARCT Levels 

For refinery boilers/heaters, ETS/AEC studied the technologies for pre-treatment of fuel gas 

prior to combustion in Module 2, and the technologies for post-treatment of flue gas after 

combustion in Module 3A. 

Regarding the pre-treatment of fuel gas prior to combustion, ETS/AEC stated that: 

“the present value of 40 ppmv total sulfur in refinery fuel gas be retained as the Best 

Available Retrofit Control Technology (BARCT) level”, and 

Regarding the post-treatment of flue gas from boilers/heaters after combustion, ETS/AEC stated 

that: 

“For the heaters and boilers, post-combustion emission control is often expensive due to 

the combination of the relatively low concentrations of SOx in flue gases and the division 

of the fuel gas stream among a number of heaters and boilers. Pre-combustion control, 

studied in Module 2, has been found to be more suitable for the majority of situations.” 

ETS/AEC’s conclusions on emission reductions (estimated from the 2005 actual emissions) and 

cost effectiveness for pre-treatment of fuel gas for boilers/heaters are: 

“The measures recommended by AEC are the measures that gave the largest expected 

SOx reduction potential while also featuring the most reasonable cost effectiveness. The 

total overall emissions reduction is approximately 0.89 tons per day SOx. 

The overall cost effectiveness for refinery fuel gas, averaged over the commercially 

available measures that AEC recommended for the refineries in this study, is estimated to 

be $16,823 per ton SOx reduced. The study team estimates that any given cost 

effectiveness number has an expected range someplace within the band of -10% to 

+50%.” 

Since ETS/AEC does not recommend a new BARCT level for boilers/heaters, staff will not 

describe this portion of ETS/AEC analysis in details, however a summary is included in 

Appendix II-A of this report. 

 
Final Staff Report – Part 2 References – Part II 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 38 November 2, 2010 

References – Part 2 

AQMD, 2008-1. South Coast Air Quality Management District – Board Meeting July 11, 2008, 

Agenda # 29: Report of RFPs and RFQs Scheduled for Release in July. July 11, 2008. 

AQMD, 2008-2. South Coast Air Quality Management District – Request for Proposal, RFP 

#P2009-01. Evaluation of Emission Control Technologies for Further Reducing Sulfur 

Oxides Emissions from Stationary Sources in the South Coast Air Quality Management 

District’s RECLAIM Program. July 11, 2008. 

AQMD, 2008-3. South Coast Air Quality Management District – Board Meeting September 5, 

2008, Agenda # 3: Execute Contract to Evaluate Emission Control Technologies for 

Further Reducing Sulfur Oxides Emissions from Stationary Sources in the SCAQMD SOx 

RECLAIM Program. September 5, 2008. 

AQMD, 2008-4. South Coast Air Quality Management District – Contract# C09104 – Contract 

with Nexidea, Inc. – Evaluation of Emission Control Technologies for Further Reducing 

Sulfur Oxides Emissions from Stationary Sources in the SCAQMD’s RECLAIM Program. 

September 5, 2008. 

AQMD, 2008-5. South Coast Air Quality Management District – Contract# C09105 – Contract 

with ETS, Inc. – Evaluation of Emission Control Technologies for Further Reducing Sulfur 

Oxides Emissions from Stationary Sources in the SCAQMD’s RECLAIM Program. 

September 5, 2008. 

NEXIDEA, 2008. SOx RECLAIM Final Report – Wet/Dry Scrubbing Technology for Sulfuric 

Acid Plants and Coke Calciner. Nexidea, Inc. - December 2008. 

ETS, 2008-1. SOx RECLAIM Study - Final Report – Module 2: Refinery Fuel Gas Treatment 

and Sulfur Recovery/Tail Gas Units. AEC Engineering Inc./ETS, Inc. April 20, 2009. 

ETS, 2008-2. SOx RECLAIM Study - Final Report – Module 3-A: Wet/Dry Scrubbing 

Technology for Refinery Fluid Catalytic Cracking Units (FCCUs), refinery Boilers/Heaters, and 

Refinery Sulfur Recovery Units (SRUs) and Tail Gas Treatment Processes. AEC Engineering 

Inc./ETS, Inc. April 20, 2009. 

ETS, 2008-3. SOx RECLAIM Study - Final Report – Module 3-D: Wet/Dry Scrubbing 

Technology for Container Glass Manufacturing Plant. ETS, Inc. December 16, 2008. 

ETS, 2008-4. SOx RECLAIM Study - Final Report – Module 3-E: Wet/Dry Scrubbing 

Technology for Cement Kilns and Coal-Fired Fluidized Bed Boiler. ETS, Inc. December 16, 

2008. 

TESORO, 2009. 

 
Final Staff Report – Part 2 Appendix A: Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 39 

Appendix A – Summary of Consultants’ Recommended Control Technology & Costs 

Type

Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refine

Control Technology 

Number of Vendors Provided 

Quotes & Vendor's Names

3 Vendors: 

BELCO, Hamon, 

MECS

3 Vendors: 

BELCO, Hamon, 

MECS

4 Vendors: 

Belco, Hamon, 

MECS, Alstom

3 Vendors: 

BELCO, Hamon, 

MECS

Vendor Guarantee/Quote #1 BELCO <5ppmv BELCO <5ppmv BELCO <5ppmv BELCO <5ppmv 

Vendor Guarantee/Quote #2 MECS 5ppmv MECS 5ppmv MECS 5ppmv MECS 5ppmv 

Inlet Parameters Provided for 

Costs & Sizing

Flow: 93 Kscfm; Temp:400-600F 

SOx: 54.8 ppmv

Flow: 225 Kscfm 

Temp: 560 oF 

SOx: 11.5 ppmv

Flow: 145 Kscfm 

Temp: 539 oF 

SOx: 20.7 ppmv

Flow:101 Kscfm 

Temp: 500 oF 

SOx: 20.6 ppmv

Flow: 65 

Temp: 5

SOx: 21.8 

Vendor for costs/sizing (note 1) BELCO BELCO BELCO BELCO BELC

Plot Space Estimated 35' L x 45' W 40' L x 50' W 40' L x 50' W 35' L x 45' W 30' L x 4

Equipment Cost ($ million) 21 39 29 24 

Capital Cost ($ million) 60 101 78 66 

Present Worth Value ($ million) 76 133 95 78 

Fluid Catalytic Cracking Units

WGS
Final Staff Report – Part 2 Appendix A: Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 40 

Appendix A (Continued) 

Type

Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 5 

Control Technology Emerachem WGS Emerachem Emerachem WGS 

Number of Vendors Provided 

Quotes & Vendor's Names

2 Vendors: Lurgi, 

Emerachem

3 Vendors: Lurgi, 

Cansolv, Tri-Mer

4 Vendors: Lurgi, 

Cansolv, 

Emerachem, TriMer

2 Vendors: Lurgi, 

Emerachem

3 Vendors: Lurgi, 

Cansolv, Tri-Mer

Vendor Guarantee/Quote #1 Emerachem: 3.85 ppmvd (95%) Emerachem: 3.85 ppmvd (95%) Emerachem: 3.85 ppmvd (95%)Vendor Guarantee/Quote #2 Tri-Mer: 

≤ 1.0 ppmv

Tri-Mer: 

≤ 1.0 ppmv

Tri-Mer: 

≤ 1.0 ppmv

Inlet Parameters Provided for 

Costs & Sizing

Flow: 109.8 Klb/hr 

Temp: 600-700 oF 

SOx: xx ppmvd 

Flow:180.6 Kacfm 

Temp: 1000 oF 

SOx: xx ppmv 

Flow: 109.8 Klb/hr 

Temp: 600-700 oF 

SOx: xx ppmvd 

Flow: 109.8 Klb/hr 

Temp: 600-700 oF 

SOx: xx ppmvd 

Flow: 48.5 Kacfm 

Temp: 1000 oF 

SOx: xx ppmv 

Vendor for costs/sizing (note 1) Emerachem Tri-Mer Emerachem Emerachem Tri-Mer 

Plot Space Estimated 25' L x 100' W 88.5' L x 67' W 25' L x 100' W 25' L x 100' W 29.5' L x 67' W (2 units required) 

Equipment Cost ($ million) 4 14 5 4 15 

Capital Cost ($ million) 13 38 13 11 39 

Present Worth Value ($ million) 26 60 17 19 64 

Sulfur Recovery Units/Tail Gas
Final Staff Report – Part 2 Appendix A – Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 41 

Appendix A (Continued) 

Type

Refinery 1 Refinery 2 R

Control Technology FGT FGT 

Number of Vendors Provided 

Quotes & Vendor's Names 2 Vendors: Shell Sulfinol, Gas Spec 2 Vendors: Shell Sulfinol, UOP 1 Vend

Vendor Guarantee/Quote #1 Sulfinol: 59% total SOx removal Sulfinol: 0.2% total SOx removal Sulfinol remova

85%, 56%Total 

Vendor Guarantee/Quote #2

UOP Merox removal of non-H2S ethyland methyl-mercaptans: 93% ethylmercaptan, 80% methly-mercaptan; 91%Total SOx reduction

Inlet Parameters Provided for 

Costs & Sizing

 Flow: 821,000 scfh, Temp: not available, SOx inlet: 42.48 ppmv

 Flow: 3 MMscfd, Temp: not available, 

SOx inlet (total mercaptans): 300 ppmv

Flow: 9.6 MMsand 20.2 MMscTemp: 100 oF, ppmv for H2S aH2S species

Vendor for costs/sizing (note 1) Gas Spec UOP 

Plot Space Estimated Small plot space required UOP: 40' L x 150' W Small pl

Equipment Cost ($ million) 0.2 5 

Capital Cost ($ million) 0.5 16 

Present Worth Value ($ million) 1.4 20 

Refinery Boilers/Heaters
Final Staff Report – Part 2 Appendix A – Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 42 

Appendix A (Continued) 

Type

Refinery 4 Refinery 5 Refine

Control Technology FGT FGT FGT

Number of Vendors Provided 

Quotes & Vendor's Names 2 Vendors: Shell Sulfinol, UOP 2 Vendors: Shell Sulfinol, UOP 2 Vendors: S

Vendor Guarantee/Quote #1 Sulfinol: 97% or 5 ppmv, 54%Total SOx reduction Sulfinol removal for Wilmington: 85% removal for non-H2S sulfur in fuel gas , 68.4%Total SOx reduction Sulfinol removal: 8

31%COS, 11%Tota

Vendor Guarantee/Quote #2 UOP Merox: 47.6% total SOx reduction

UOP Merox removal of Carson non-H2S ethyl- and methyl-mercaptans (191.4 ppmv of total): 93% ethyl-mercaptan, 80% methlymercaptan; 90%Total SOx reduction

UOP Merox: 7.

reduct

Inlet Parameters Provided for 

Costs & Sizing

Flow: 19,059 MMscf/yr, 

Temp: 100 oF, 

SOx inlet: 146 ppmv

Location A--> Flow:14 MMscfd, Temp:100 

oF, SOx: 50 ppmv. Location B--> Flow:20 MMscfd, Temp:not available, SOx: 200 ppmv

Flow: 42.4 MMscfd

SOx: not a

Vendor for costs/sizing (note 1) Shell Shell + UOP She

Plot Space Estimated Small plot space required Shell:small plot space required for Location A. UOP: 40' Lx150' W for Location B Small plot spa

Equipment Cost ($ million) 5 21 9 

Capital Cost ($ million) 13 53 23 

Present Worth Value ($ million) 16 64 21 

Refinery Boilers/Heaters
Final Staff Report – Part 2 Appendix A – Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 43 

Appendix A (Continued) 

Type

Fac C Fac A Fac A 

Control Technology WGS Equip Modification WGS 

Number of Vendors Provided 

Quotes & Vendor's Names

4 Vendors: BELCO, TriMer, MECS, Cansolv 4 Vendors: BELCO, Tri- Mer, MECS, Cansolv 4 Vendors: BELCO, Tri- Mer, MECS, Cansolv 4 Vendo

Mer, M

Vendor Guarantee/Quote #1 MECS: <10 ppmv, expected <5 ppmv MECS: <10 ppmv, expected <5 ppmv MECS: <10 ppmv, expected <5 ppmv MEC

expe

Vendor Guarantee/Quote #2

BELCO: <10 ppmv, 

<5ppmv is achievable 

with existing scrubbers

BELCO: <10 ppmv, 

<5ppmv is achievable with 

existing scrubbers

BELCO: <10 ppmv, 

<5ppmv is achievable 

with existing scrubbers

BELC

<5ppm

wi

s

Inlet Parameters Provided for 

Costs & Sizing

Flow: 205,000 acfm 

Temp: 405 oF 

SOx inlet: 50 ppmv

Flow: 27,383 acfm 

Temp: 86 oF 

SOx inlet: 20 ppmv

Flow: 27,383 acfm 

Temp: 86 oF 

SOx inlet: 20 ppmv

Flow

Tem

SOx i

Vendor for costs/sizing (note 1) BELCO (Note 2) Cansolv (Note 3) BELCO (Note 4) BEL

Plot Space Estimated 30' L x 40' W No plot space needed 15' L x 20' W 20

Equipment Cost ($ million) 8.2 8.2 0.5 2.3 

Capital Cost ($ million) 13.3 13.3 0.5 3.1 

Present Worth Value ($ million) 25.3 25.3 1.7 8.0 

Coke Calciner Sulfuric Acid Plant

Total Costs for 

Calciner
Final Staff Report – Part 2 Appendix A – Summary of Consultants’ Recommended Con

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part II - 44 

Appendix A (Continued) 

Type

Control Technology WGS Limestone Absorber DGS or Limestone Absorb

Number of Vendors Provided 

Quotes & Vendor's Names

4 Vendors: Tri-Mer (NWGS), 

MECS (NWGS), McGill 

(NWGS), Dustex (DGS), PPC 

(Process Mod)

3 Vendors: MECS (NWGS), 

BoldEco (Limestone Absorber), 

BoldEco (Hybrid DGS + 

Baghouse), Dustex (Hybrid DGS + 

Baghouse)

4 Vendors: MECS (NWGS

BoldEco (Limestone Absorb

BoldEco (Hybrid 

DGS+Baghouse), Dustex 

(Hybrid DGS+Baghouse), S

Vendor Guarantee/Quote #1 MECS: 90% (<10 ppmv) MECS: 90% (<10 ppmv) MECS: 90% (<10 ppmvVendor Guarantee/Quote #2 McGill: 95% (5 ppmv) BoldEco Limestone Absorber: 95% (<2 ppmv) BoldEco Limestone Absorber: 95% (5 ppmv

Inlet Parameters Provided for 

Costs & Sizing

Flow: 30,000 - 60,000 acfm 

Temp: 650 - 675 oF 

SOx inlet: 100 ppmv

Flow: 170,000 - 203,000 acfm 

Temp: 275 oF 

SOx inlet: 25 ppmv

Flow: 60,000 acfm 

Temp: 275 oF 

SOx inlet: 100 ppmv

Vendor for costs/sizing (note 1) Tri-Mer BoldEco BoldEco

Plot Space Estimated 32' L x 10' W 50' L x 40' W Solios:10' Diax71' H Boldeco:35' Diax35' H

Equipment Cost ($ million) 1.1 1.1 16.6 4.7 

Capital Cost ($ million) 1.9 1.9 19.6 6.1 

Present Worth Value ($ million) 8.8 8.8 43.7 12.6 

Total Costs for Glass

Glass Plant Cement Plant
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

_______________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 45 November 2, 2010 

Appendix B – Consultants’ Biographies 

This section includes the biographies of the consultants. Staff will add more in a near future. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 46 November 2, 2010 

MARSHALL A. (BUD) BELL 

PRESIDENT CARSON INDUSTRIAL STEAM COMPANY 

1639 THIRD STREET 

MANHATTAN BEACH, CA 90266 

310-376-4144 HOME 

310-376-7194 FAX 

310-951-8972 CELL 

mbbells@earthlink.net 

EDUCATION 

1966 BS CHEMICAL ENGINEERING-CLEMSON UNIVERSITY 

1968 MS CHEMICAL ENGINEERING- GEORGIA TECH 

1994 EXECUTIVE MBA-CLAREMONT GRADUATE UNIVERSITY 

Mr. Bell has a very strong background in refining and power technologies, and in plant operations and 

management. He has 41 years of refining and power experience, covering activities ranging from 

research and development to refinery operations and maintenance work; and has held the position of 

General Manager of Refining for a prototype heavy crude refinery. During his tenure as General 

Manager, the refinery achieved record levels of profitability, safety and environmental compliance. Mr. 

Bell provided much of the strategic planning for Conoco/Phillip’s Wilmington Refinery, and helped 

develop and bring to the market several new refining technologies. He is currently President of Carson 

Industrial Steam Company, and is developing a large residual oil-fired cogeneration complex in 

southern California. Mr. Bell recently completed a three-year assignment as Owner’s Engineer on a 

world-scale gasification project in North America. 

EXPERIENCE 

Mr. Bell’s most recent job in refining was as Process Manager for Conoco/Phillips Petroleum 

Company's Wilmington, California refinery. While in this position, Mr. Bell worked as part of a 

project team assessing the technical and economic merits of building an 8,000 TPD IGCC plant at the 

refinery. He helped set the design basis, evaluated potential gasification technologies and assisted in 

developing the plant layout and coke handling systems. He also advised the development team on 

ways to maximize project returns, and on ways of meeting the very stringent air emission standards. 

During his tenure at this refinery, Mr. Bell helped develop, design and build the most sophisticated 

flue gas SO2 removal system in the refining industry. He also developed a novel approach to cracking 

jet fuel at low pressure to produce California-grade gasoline and isobutane. 

Mr. Bell was previously Technology Manager for Petroleum Refining for Black & Veatch Pritchard 

(BVPI) in Overland Park, Kansas. In this role, he was responsible for all aspects of petroleum refining 

and petrochemical technologies. He assisted the Power Division in assessing the viability of several 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 47 November 2, 2010 

direct-fired and IGCC power projects, and spent considerable time with the Power Group doing 

business development, both in the U.S. and overseas. Mr. Bell was involved in the training of engineers 

from major oil companies in the basics of power production using various technologies. 

After leaving Conoco/Phillips, Mr. Bell began development of a 600 MWeq petroleum coke-fired 

cogeneration project in the Los Angeles basin. The project will burn petroleum coke in an ultrasupercritical steam boiler to generate power and process steam, while meeting the most stringent air 

quality standards in the world. The project will have the capability of removing 90 per cent of the CO2 

in the boiler flue gas at less than $50 per tonne cost. 

Mr. Bell also recently completed a three-year assignment as Owner’s Engineer on a world-scale 

gasification project for a fertilizer plant in North America. The plant will gasify up to 15,000 TPD of 

coal or pet coke to make syngas for an IGCC unit, plus hydrogen for an ammonia/urea complex. Mr. 

Bell created the physical and economic model of the facility, as well as a pro forma model for various 

feedstocks and product offtakes. He provided novel ways of reducing capital and operating costs for the 

project, while increasing plant throughput. 

Prior to joining BVPI, Mr. Bell was Product Line Manager for Refining for Brown and Root Braun in 

Alhambra, California. In this position, he was responsible for the basic designs of refining and 

petrochemical units, and the proper execution of process designs on refining projects. Mr. Bell’s 

previous assignment with Brown and Root Braun was as Chief Process Engineer, where he supervised 

approximately 75 Process Engineers on numerous refining, petrochemical, ammonia and ethylene 

studies and projects. 

Prior to joining Brown and Root, Mr. Bell was General Manager of Refining for Ultramar Refining 

Company’s 75,000 BPD heavy crude refinery in Wilmington, California. Under his guidance, the 

refinery established the best refinery environmental record in the Los Angeles basin, and one of the 

best safety records in the refining industry. Mr. Bell also held Operations Manager and Technical 

Manager position with Champlin Petroleum Company, the predecessor to Ultramar at the Wilmington 

plant. 

Prior to joining Champlin, Mr. Bell held a number of engineering and management positions with 

Chevron in their Richmond and El Segundo, California facilities, and was involved with two major 

expansions of both refineries. 

Mr. Bell’s first industrial job was as a Technical Services and Operations Engineer with Shell Chemical 

Company in Martinez, California. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 48 November 2, 2010 

ROBERT G. KUNZ, PH.D.

504 ALANBROOK COURT

HILLSBOROUGH, NC 27278-7733 

RESIDENCE: (919) 245-1560

OFFICE: (919) 245-1569

E-MAIL: KUNZRG@AOL.COM

OBJECTIVE Continuing participation in trend-setting environmental control 

activities utilizing proven strengths in planning, organization, analysis, 

and formulation of strategy to reduce costs, develop technology, and 

prevent downtime. 

BACKGROUND 

SUMMARY

Professional with over 40 years experience and a consistent track record 

of completing projects on spec, on time, and on budget. Areas of 

accomplishments include leadership, negotiation skills, problem 

solving, and the ability to correlate diverse facts. Excellent 

communicator with the talent to instruct, train, and mentor others. 

Earned both Ph.D. and M.B.A. degrees. Published technical author 

including book, journal articles, presentations, and one patent. 

Experienced team leader. Skills range from management to research 

and development, with awards received in both areas. 

Expertise in petroleum refining and chemical / gas plants: 

• Air emission control and testing 

• Cooling water treatment and corrosion control 

• Processes including fluid catalytic cracking 

• Wastewater treatment 

• Noise generation, control, and measurement 

• Environmental permitting 

SELECTED ACCOMPLISHMENTS 

• Designed, built, and operated a pioneering pilot SO2 and particulate flue-gas scrubber on 

fluid catalytic cracker (FCC) regenerator, allowing installation of full-scale scrubber at oil 

refinery to meet new air quality regulations. 

• Led a team to respond quickly to pinpoint source of excessive particulate emissions from 

electrostatic precipitator treating cat cracker regenerator flue gas and others at California oil 

refinery. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 49 November 2, 2010 

• Co-authored U.S. patent while serving on elite task force to identify high-cost and missing 

technology necessary to comply with increasingly stringent environmental regulations in the 

refining industry. 

• Over a 15-yr period, managed engineering group and supervised a team of environmental 

professionals responsible for negotiating environmental approvals needed for construction of 

new plants / projects. No capital project was ever delayed by failure to obtain permits in a 

timely manner. 

• Served as member of "SWAT" team in discretionary siting of new $20M - $30M industrial 

gas plants to identify any fatal flaws which might prevent, delay, or jeopardize plant 

construction or unduly increase the cost. 

• Supported sales of hydrogen gas to petroleum industry by providing expertise in 

environmental regulatory compliance. 

• Developed a correlation to predict hydrogen reformer furnace NOx emissions (later extended 

to ethylene plants). Presented results at industry conferences and in the technical literature. 

• Secured permits for and field-tested selective catalytic reduction (SCR) units, a postcombustion NOx control technique, located at / adjacent to several refineries / chemical 

plants. Published findings in Journal of the Air & Waste Management Association.

• Developed procedure for forecasting SCR catalyst life to prevent untimely shutdown of 

operations, presented at a petroleum industry conference and published in the literature 

(Environmental Progress). 

• Presented technical paper on the successful application of SCR to FCC units at multiple 

locations. This presentation at a petroleum industry conference was co-authored by the SCR 

system manufacturer and a representative of a U.S refinery. 

• Directed multi-location environmental site assessment for $65M acquisition, which was 

completed on schedule and at less than 50% of budget, allowing timely acquisition of new 

product line. 

• Formulated the "Kunz Equation," which correlates system pH from alkalinity measurements 

in over 100 cooling towers to allow independent cooling water calculations, used as 

objective criteria to evaluate vendor proposals. These procedures were published in 

Chemical Engineering magazine and are now taught in college classrooms. 

• Received Harrison Prescott Eddy Medal, a prestigious award given annually by the Water 

Pollution Control Federation, for noteworthy research in wastewater treatment. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 50 November 2, 2010 

PROFESSIONAL EXPERIENCE 

RGK ENVIRONMENTAL CONSULTING, L.L.C., Hillsborough, NC 2003-Present 

Independent Consultant / Author 

CORMETECH, INC. ENVIRONMENTAL TECHNOLOGIES, Durham, NC 2001-2003 

Technical Project Manager 

AIR PRODUCTS AND CHEMICALS, INC., Allentown, PA 1974-2000 

Senior Engineer / Manager / Senior Engineering Associate 

ESSO RESEARCH AND ENGINEERING COMPANY, Florham Park, NJ

1968-1974 

Engineer / Project Engineer 

MILITARY SERVICE 

Lieutenant, United States Air Force - Honorably separated from Active Duty and transferred to 

Retired Reserve. 

Received Certificate of Outstanding Achievement from United States 17th Air Force for 

Communications Cost Reduction and Management Improvement Programs at conclusion 

of final assignment. 

 

EDUCATION 

Ph.D., Chemical Engineering, Rensselaer Polytechnic Institute, Troy, NY 

M.B.A.., Executive Program, Temple University, Philadelphia, PA 

M.S., Environmental Engineering, Newark College of Engineering, Newark, NJ 

B.Ch.E. (with honors), Chemical Engineering, Manhattan College, Bronx, NY 

Additional college courses in Psychology, Economics, Accounting, and Marketing 

PROFESSIONAL LICENCES 

Registered Professional Engineer NJ, PA, AL, TX, LA 

Former Certified Community Noise Measurement Specialist, NJ 

PROFESSIONAL ASSOCIATIONS 

American Institute of Chemical Engineers (AIChE) 

American Chemical Society (ACS) 

Air & Waste Management Association (A&WMA) 

Sigma Xi - The Scientific Research Society 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 51 November 2, 2010 

 

JOHN D. MCKENNA 

ETS, Inc. 

 1401 Municipal Road 

 Roanoke,VA 24012

 540-265-0004 ext293 

 jmck@etsi-inc.com

EDUCATION 

B.S.Ch.E. - Manhattan College - 1961 

M.S.Ch.E. - New Jersey Institute of Technology - 1968 

M.B.A. - Rider University - 1974 

Ph.D. - Walden University - 1991 

Doctoral Thesis Topic: A Study of Factors Underlying Growth for Industrial Firms During Their 

Early Years After Startup 

Master Thesis Topic: The Effect of Nitrilotriacetic Acid Upon the Biodegradability of Synthetic 

Detergents 

Certified On-line Trainer - Walden University - 2000 

EXPERIENCE 

Dr. McKenna has over forty years of technical and business management experience. His background 

includes a wide range of entrepreneurial activities including the start-up of six environmental firms, one 

of which he took public. His direct experience includes corporate acquisitions and mergers as well as 

the invention and commercialization of a flue gas desulphurization (FGD) system. In light of the weak 

USA market conditions, an office was established in Taiwan and thereby the initial FGD system sales 

were achieved. In 1996, ETS International Inc. was listed in “The Nations Fastest Growing 

Technology Companies,” having recorded a 5-year revenue growth of 542%. In addition to business 

and technical management experience, he has also been providing international training for over 30 

years. Currently he is a principal of ETS Inc. He has taught online business and environmental courses 

for the University of Phoenix. 

2002-2007 Co-chair Southampton Corp 

A private venture capital firm specializing in the environmental industry. 

2002-2006 University of Phoenix 

Teaching on-line: Management, Marketing, Environmental Ethics, Environmental Science 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 52 November 2, 2010 

1999-present Principal ETS Inc. 

A provider of environmental training, testing, troubleshooting and testimony. 

Chairman/President, ETS International, Inc. 

Responsible for general management and long range planning functions. 

Program Manager – FGD (LEC) – Full Scale Commercial Systems. 

President, ETS, Inc., June 1979 to June 1988. 

Responsible for general management and R&D strategic planning/priorities 

Program Manager – Pilot Plant FGD (LEC) Semi-Dry System. 

President, January l, 1978 to June 1979. 

Enviro-Systems & Research, Inc. and Environmental Testing Services, Inc. Director '72-'82. 

Vice President, Enviro-Systems & Research. 

Directed all application engineering, research and development related to air and water pollution 

control. Concentration of effort on fabric filters, mechanical collectors and scrubbers for a wide variety 

of industrial applications. Program manager for million dollar EPA contract. 

1968-72 Research Cottrell, Projects Director of Environmental Systems Division. 

Supervised the development of RC's wet limestone scrubber for SO2 removal FGD Pilot Plant and first 

RC full scale FGD system at Arizona Public Service. Responsible for execution of all projects and 

laboratory activities for both air and water pollution control, including in-house research and 

development and industrial and EPA R&D contracts. Supervised technical services which 

encompassed stack and stream sampling, laboratory analytical determinations, bench analysis, pilot 

plant fabrication and research. Major R&D efforts, oriented to particulate control and SO2

removal. Consulting included comprehensive pollution control studies for complete industrial plants. 

1967-68 Princeton Chemical Research, Project Leader. 

Assigned to execute industrial and government contracts for water and air pollution control, including a 

NAPCA contract concerned with SO2 control by catalytic reduction. 

1964-67 Eldib Engineering & Research, Inc., Technical Assistant to the President. 

Senior Engineer for pollution control problem solving. Investigated industrial wastewater, municipal 

sewage and industrial air pollution problems. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 53 November 2, 2010 

PROFESSIONAL ACTIVITIES 

Air and Waste Management Association Technical Council – AE Chair 2002-2005 

Virginia Environmental Business Council – Board of Directors 2000-2004 

Air and Waste Management Association Technical Program – Chairman, Specialty Conference Fabric 

Filter VII 1994 

Air and Waste Management Association South Atlantic Section – Board of Directors 1993-1996 

Virginia State Advisory Board of Air Pollution – 1992 Vice Chair, 1993 Chair 

Advisory Board Member: Wiley Series in Chemical Engineering 

Air and Waste Management Association Technical Program – Chairman, Specialty Conference Fabric 

Filter VI 1992 

Technical Program Committee, Scientific Evaluation of the National Acid Precipitation Assessment 

Program's (NAPAP), Final Report – 1991 

Technical Advisory Committee, Ohio Air Quality Development Authority (OAQDA) – 1991 

Air and Waste Management Association Emission Control Technology - Division Chairman, 1988-

1991 

Air and Waste Management Association Technical Program – Chairman, Specialty Conference Fabric 

Filter V 1990 

NSF Consultant for the College Faculty Workshop Program-Grant 

EPA Fabric Filter Workshop Lecturer 

Scientific Reviewer for EPA Publications 

AIChE - Central VA Section – Chairman 1980-84 

APCA Lecturer "Particulate Control Device Cost Optimization" 

Member of National Association of Environmental Professionals 

EPA Course 413 Lecturer, "Fabric Filters and Selection and Cost of Control Equipment." – Presented 

at Rutgers University, March 18-19, 1987. 

LISTINGS AND AWARDS 

Distinguished Alumni Medal for Outstanding Achievement - New Jersey Institute of Technology 

Manhattan College School of Engineering Centennial Award - Outstanding Engineering Graduate 

New York Xi, Chapter of Tau Beta Pi, National Honor Society of Engineering - Eminent Engineer 

Fellow -- American Institute of Chemical Engineers 

Fellow – Air and Waste Management Association. 

Who's Who in Engineering 

Who's Who Environmental Registry 

Who's Who in Finance and Industry 

Who's Who in Technology Today 

Who's Who in the World 

Who's Who in Science and Engineering 

Appointed by VA Governor G. Allen 97-01 World Trade Alliance of the Blue Ridge 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 54 November 2, 2010 

COMMUNITY ACTIVITIES 

Chairman, Roanoke Catholic School Board, 1984-1986 

Roanoke Memorial Hospital Pastoral Care Visitor 1988-1992 

TRAINING COURSES DELIVERED 

Domestic 

Fine Particle Emission Measurement & Control 

Toxic Air Pollutants - Prevention and Control 

Particulate Emission Control Cost Optimization 

Introduction to Air Pollution Control 

Introduction to Water Pollution Control 

Incineration 

Regulatory and Permitting Policies 

Particulate Emission Control 

Gaseous Emission Control 

Baghouse Operation and Maintenance 

Project Costs and Financing 

Project Management 

Public Involvement in Large-Scale Development Projects with Significant Environmental Impacts - 

AED/USAID for Russian Group 

Pollutant Release and Transfer Registers Program - AED/USAID for Ukrainian Group 

Foreign 

Developing and Implementing Emission Inventories - Saudi Arabia/SABIC 

Energy and the Environment - Univ. of La Laguna - Canary Islands 

Baghouse Technology - National Taiwan University - Taipei, Taiwan 

Air Pollution Technology Workshop - Floreanopolis, Brazil - IIE/USAEP 

Methods of Effective Environmental PR - AED/USAID Kazakhstan 

National Park Management Capacity Building - AED/USAID Armenia 

PROJECT MANAGEMENT EXPERIENCE 

John D. McKenna has gained comprehensive technical project management experience over the past 40 

years. 

In 1967-1968, while at Princeton Chemical Research, Dr. McKenna was the Program Manager of a 

research project funded by the National Air Pollution Control Agency (NAPCA) to evaluate SO2

control by catalytic reduction. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 55 November 2, 2010 

While at Research Cottrell, during 1968-1972, he was the Program Manager on an EPA/HEW project 

which dealt with the design, installation, operation and testing of a wet scrubbing pilot plant for SO2

control. Managed pilot wet scrubber FGD testing at AEP (Tidd Station) and RC’s first full scale SO2

FGD system at Arizona Public Service (Cholla Station). 

During this time, he was also the technical manager of a program funded by Research Cottrell to 

acquire and develop the RC/Bacho system for SO2 removal. 

In 1973, Dr. McKenna was the Program Manager of EPA 68-02-1093. The purpose of this ETS 

contract was to conduct a preliminary techno-economic evaluation of the application of fabric filters to 

coal-fired industrial boilers. The success of this project led to a larger scale demonstration program 

(EPA 68-02-2148) and a subsequent follow on program (EPA 68-02-3674) both managed by Dr. 

McKenna. 

In 1976, he managed a program to install, operate and test a fabric filter pilot plant on the slipstream of 

a refuse-fired boiler. The study, EPA R804223, was initiated to determine if a fabric filter was a viable 

control alternative for this application. 

In 1981, Dr. McKenna managed an ETS contract received from EPA Region 5 (EPA task order 116) to 

execute an air pollution control engineering study. The purpose of this study was to settle a dispute 

between a federal agency and state government. In this effort, ETS technical personnel successfully 

executed 12 major tasks both within budget and on schedule. 

In 1982, he managed a major ETS environmental engineering contract funded by the Government of 

Mexico. The program objectives were to design and specify a continuous ambient monitoring network 

for a developing industrial port and surrounding residential towns on the west coast of Mexico. Not 

only did the program involve the management of ETS technical personnel, but also the coordination of 

activities between ETS and several consulting subcontractors, Mexican authorities and various 

Mexican industrial representatives. 

In 1983, ETS received a contract (EPA 68-02-3649) to characterize the performance of fabric filters on 

three large utility boilers. This program not only demonstrated the field testing and other technical 

capabilities of ETS, but also Dr. McKenna's program management abilities since two major 

subcontractors were involved (RTI and TRC) and field teams of over 20 engineers, scientists and 

technicians were mobilized. 

In 1985, he was the ETS manager in a program in which ETS was subcontractor to Malcolm Pirnie. 

The program was funded by the Power Authority of the State of New York (PASNY). The purpose 

was to evaluate the techno-economic feasibility of applying fabric filtration and dry scrubbing to 

control MSW emissions. The major outputs of the study included capital and operating costs estimates 

and recommended design specifications for the subject control techniques. 

Dr. McKenna has managed an ETS program funded by the Ohio Coal Development Office. The 

program initiated in 1987, evaluates an approach to control acid rain precursors. In this program, he 

has been responsible for the coordination of all activities between ETS and the prime contractor, Ohio 

University. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 56 November 2, 2010 

In the 1990s managed EPA Contract No. 68D20029, "Source Testing and Method Evaluation for 

Stationary Source Emissions." 

From 1998 to present via an ETS subcontract from RTI, he has been the manager of the Air Pollution 

Control Technology (APCT) Business and Marketing Planning activity for EPA’s Environmental 

Technology Verification Program (EPA Coop. Agreement CR826152-01-0). He has also provided the 

coordination and technical support of the APCT’s Baghouse Filtration Products (BFP) Verification 

Program. This activity includes the preparation of generic protocols and test Q/A plans, review and 

coordination of recommended modifications to existing generic protocols and test Q/A plans, and 

continued review and commentary of the BFP verification process. 

In 2008-2009 Dr. McKenna managed an ETS contract received from the South Coast Air Quality 

Management District (SCAQMD) for the evaluation of emission control technologies for further 

reducing sulfur oxide emissions from stationary sources in the SCAQMD’s RECLAIM program. The 

purpose was to identify the Best Available Retrofit Control Technologies (BARCT) that could be 

implemented within the 2011-2014 timeframe to help South Coast Basin attain the PM2.5 ambient air 

quality standards. The industries covered included refineries, cement manufacturing, and container 

glass manufacturing. 

PUBLICATIONS – TEXTBOOKS 

McKenna, John D.; Turner, James H.; "Fabric Filter - Baghouses I Theory, Design, and Selection." 

Published in 1989, ETS, Inc., Roanoke, VA. 

Mycock, John C.; McKenna, John D.; Theodore, L.; "Handbook of Air Pollution Control Engineering 

and Technology" Published by Lewis Publishers, 1995. 

McKenna, John D.; Turner, James H.; McKenna, James P., “Fine Particle (2.5 Microns) Emission 

Regulations, Measurement and Control” Published by John Wiley & Sons Inc., 2008 

PUBLICATIONS – TEXTBOOK CHAPTERS 

McKenna, John D.; Greiner, Gary P.; "Air Pollution Control Equipment: Operation and Maintenance"; 

Chapter 8: "Baghouses" - Published in 1982, Prentice Hall, Englewood Cliff, NJ. Ed. Theodore & 

Buonicore. 

Turner, J.H.; McKenna, J.D.; "Control of Particles by Filters", Chapter in Air Pollution Technology 

Handbook, Seymour Calvert, ed. John Wiley & Sons, Inc., 1984. 

Turner, J.H.; Lawless, P.A.; Yamamoto, T.; Coy, D.W.; Greiner, G.P.; McKenna, J.D.; Vatavuk, W.M; 

"Electrostatic Precipitators," Chapter 3 in Air Pollution Engineering Manual, Van Nostrand Reinhold, 

New York, NY, Ed. by Buonicore, A.J. and Davis, W.T., 1992. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 57 November 2, 2010 

McKenna, J.D.; Furlong, D.A.; "Fabric Filters," Chapter 3 in Air Pollution Engineering Manual, Van 

Nostrand Reinhold, New York, NY, Ed. by Buonicore, A.J. and Davis, W.T., 1992. 

Mc Kenna, John D. “Air Pollution Management of Stationary Sources” Section 25 in Perry’s Chemical 

Engineer’s Handbook, Seventh Edition, Mc Graw-Hill, NYC, 1997 

PUBLICATIONS – ARTICLES AND PRESENTATIONS 

McKenna, J.D.; Eldib, I.A.; New Markets for Chemicals and Equipment to Combat Pollution. 

Presented at Farleigh Dickinson University Summer Conference, "The Demands of Pollution Control 

Legislation", August 22-26, 1966. Cited in C&EN 44, 37 (Sept. 4, 1966). 

M.S. Thesis: The Effect of Nitrilotriacetic Acid Upon the Biodegradability of Linear Alkylbenzene 

Sulfonate (1968). 

McKenna, J.D.; Evaluation of a Two-Stage Particulate Scrubber and Gas Absorber Applied to Power 

Plant Flue Gas. Presented at the NAPCA International Symposium on Wet Limestone Scrubbing, 

Pensacola, FL, March 16-20, 1970. 

McKenna, J.D.; Atkins, R.S.; The RC/BAHCO System for Removal of Sulfur Oxides and Fly Ash 

from Flue Gases, Power Engineering, May 1972, pp. 50-52. Presented at the 

 

Second International Lime-Lime-Stone-Wet Scrubbing Symposium, New Orleans, LA, Nov. 8-12, 

1971. 

McKenna, J.D.; The International Competitiveness of the U.S. Air Pollution Control Industry. 

Presented at the International Air Pollution Control and Noise Abatement Exhibition, Jonkoping, 

Sweden, September 1971. 

Gleason, R.J.; McKenna, J.D.; Scrubbing of Sulfur Dioxide From a Power Plant Flue Gas. Presented at 

the 69th National Meeting of the American Institute of Chemical Engineers, Cincinnati, OH, May 

16-19, 1971. 

Roberts, R.M.; et al; Systems Evaluation of Refuse as a Low Sulfur Fuel, November 1971, EPA 

Contract CPA 22-69-22. 

McKenna, J.D.; Coy, D.W.; Techno-Economic Selection in Times of Changing Costs and Performance 

Requirements. Published in the Proceedings of the Fifth Annual Northeast Regional Anti-Pollution 

Conference, University of Rhode Island, July 1972. 

McKenna, J.D.; Applying Fabric Filtration to Coal-Fired Industrial Boilers. Environmental Protection 

Technology Series, July 1974, 

EPA-650/2-74-058. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 58 November 2, 2010 

McKenna, J.D.; Mycock, J.C.; Lipscomb, W.O.; Performance and Cost Comparisons Between Fabric 

Filters and Alternate Particulate Control Techniques. Presented at the symposium on the "Use of 

Fabric Filters for the Control of Submicron Particulates", 4/8/74, Boston, MA. Sponsored by the 

Environmental Protection Agency and GCA Corporation. 

McKenna, J.D.; Weisberg, R.; A Pilot Scale Investigation of Fabric Filtration as Applied to Coal Fired 

Industrial Boilers. Published in the Proceedings of the Fourth Annual Industrial Air Pollution Control 

Conference, University of Tennessee, March 28, 1974, Knoxville, TN. 

McKenna, J.D.; The Application of Fabric Filter Dust Collectors to Coal-Fired Boilers. Presented at 

the Fourth Annual Environmental Engineering & Science Conference, Louisville, KY, March 4, 1974. 

Theodore, L.; et al; Selected Problems in Design of Air Pollution Equipment. National Science 

Foundation, August 1975, NTIS PB 246-363 (Contributing consultant). 

McKenna, J.D.; Mycock, J.C.; Lipscomb, W.O.; Applying Fabric Filtration to Coal-Fired Industrial 

Boilers: A Pilot Scale Investigation. EPA Technical Services, August 1975, EPA 650/2-74-058a. 

McKenna, J.D.; and Brandt, K.D.; Demonstration of a High Velocity Fabric Filtration System Used to 

Control Fly Ash Emissions. Presented at The Third Symposium on Fabric Filters for Particle 

Collection, Tucson, AZ, December 1977. 

McKenna, J.D.; Greiner, G.P.; Brandt, K.D.; Applying High Velocity Fabric Filters to Coal-Fired 

Industrial Boilers. Presented at the Symposium on the Transfer and Utilization of Particulate Control 

Technology, sponsored by the U.S. Environmental Protection Agency at the University of Denver, 

Denver, CO, July 24-28, 1978. 

McKenna, J.D.; Mycock, J.C.; Miller, R.L.; Brandt, K.D.; Applying Fabric Filtration to Refuse-Fired 

Boilers: A Pilot-Scale Investigation. EPA Contract No. R804223, May 1978, Office of Energy, 

Minerals and Industry, U.S. Environmental Protection Agency, EPA-600/7-78-078. 

McKenna, J.D.; Mycock, J.C.; Brandt, K.D.; Szalay, J.F.; Assessment of a High Velocity Fabric 

Filtration System used to Control Fly Ash Emissions. Annual Report for Contract No. 68-02-2148 for 

the U.S. Environmental Protection Agency, April 1979. 

Richardson, J.W.; McKenna, J.D.; Mycock, J.C.; An Evaluation of Full Scale Fabric Filters on Utility 

Boilers. Presented at the Fourth Symposium on the Transfer and Utilization of Particulate Control 

Technology, Houston, TX, October 11-15, 1982. 

Beachler D.S.; Richardson, J.W.; McKenna, J.D.; Mycock, J.C.; ETS, Inc., and Harmon, D., EPA - 

Emission Reduction Performance and Operating Characteristics of a Baghouse Installed on a 

Coal-Fired Power Plant, August 1984, EPA Contract 68-02-3649. 

McKenna, J.D., Ross, J.M., Foster, J.M., Gibson, R.A., Continued Assessment of a High-Velocity 

Fabric Filtration System Used to Control Fly Ash Emissions, EPA-600/7-84-037, March 1984. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 59 November 2, 2010 

McKenna, J.D., Ross, J.M.; What One Small Environmental Firm Requires of Its Chemists. Presented 

at the 62nd Annual Meeting of American Institute of Chemists, Hollywood, Florida, April 1985. 

Richardson, J.W., McKenna, J.D., Mycock, J.C., Evaluation of Full Scale Fabric Filters on Utility 

Boilers: SPS Harrington Station Unit 3, NTIS PB85-235513/WEP, July 1985. 

Richardson, J.W., McKenna, J.D., Mycock, J.C., Evaluation of Full Scale Fabric Filters on Utility 

Boilers: PP and L Brunner Island Station Unit 1, NTIS PB85-235521/WEP, July 1985. 

Mycock, J.C., McKenna, J.D., Richardson, J.W., Baghouse Troubleshooting - A Case History. 

Presented at the Professional Development Conference - Developments in Filtration Technology, 

Clemson University, May 14-15, 1986. 

Greiner, G.P., Smith, J.K., Ross, J.M., McKenna, J.D., Demonstration, Operation, and Testing of a 

Fabric Filter on an Industrial Boiler for an Extended Period of Time, EPA-600/7-86-030, September, 

1986. 

McKenna, J.D., Haley, L.H., Industrial Fabric Filter Bag Test Methods: Usefulness and Limitations. 

Presented at the ASTM Symposium on Gas and Liquid Filtration, Philadelphia, PA, October 20-22, 

1986. 

McKenna, J.D., Furlong, D.A., Baghouses As Applied to Municipal Solid Waste Incinerators. 

Presented at Filtration Technology Conference in Clemson, SC, April 15-16, 1987. 

Kapner, M., Schwarz, S., McKenna, J., An Evaluation of Alternate Emission Control Systems for 

Refuse-to-Energy Plants. Presented at the 80th Annual Meeting of APCA, New York, NY, June 21-26, 

1987. 

Turner, J.H.; Viner, A.S.; Jenkins, R.E.; Vatavuk, W.M.; McKenna, J.D.; Sizing and Costing of Fabric 

Filters, JAPCA September, 1987 issue, Volume 37, Number 9, Page 1105. 

Turner, J.H.; Lawless, P.A.; Yamamoto, T.; Coy, D.W.; Greiner, G.P.; McKenna, J.D.; Vatavuk, W.M.; 

Sizing and Costing of Electrostatic Precipitators, JAPCA April, 1988 issue, Volume 38, Number 4. 

McKenna, J.D.; Toxic Particulate Control. Presented at the EPA Workshop on Hazardous and Toxic 

Air Pollutant Control Technologies and Permitting Issues, Raleigh, NC, March 22-23, 1988 and San 

Francisco, CA, April 12-13, 1988. 

Bahner, Mark A. and John D. McKenna; Inlet-Precharged Limestone Emission Control (LEC). 

Presented at the American Filtration Society Annual Meeting - Fine Particle Filtration & Separation, 

Minneapolis, MN, April 22-24, 1991. 

Prudich, M.E.; Reddy S. N.; McKenna, J.D.; Appell, K.W.; A Pilot Demonstration of the Moving-Bed 

Limestone Emission control (LEC) Process. Paper presented at the 1991 EPRI/EPA/DOE SO2 Control 

Symposium, Washington, DC, December 306, 1991. Also presented at the 85th Annual Meeting and 

Exhibition of the AWMA, Kansas City, MO, June 21-26, 1992. 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 60 November 2, 2010 

McKenna, J.D.; Energy and the Environment. Presented to graduate students at LaLaguna University, 

Tenerife Island, Spain, November 8, 9, 10, 1993. 

Prudich, M.D.; Appell, K.W.; McKenna, J.D.; Pilot-Scale Limestone Emission Control (LEC) Process: 

A Development Project. Final Report - March 1994. 

McKenna, J.D.; Mycock, J.C.; Fabric Filter Baghouse Seminar. Presented at National Taiwan 

University, Taipei, Taiwan, R.O.C., October 12, 13, 14, 1994. 

Mc Kenna, J.D.: ETS, Inc. 1st International Cleanable Filter Symposium: Status of EPA’s Baghouse 

Filtration Products / Environmental Technology Verification Program. Chiba-Ken, Japan. The 

Association of Powder Process Industry and Engineering, Japan (APPIE) November 15, 2000. 

Mc Kenna, J.D. :ETS, Inc. 2nd International Cleanable Filter Symposium: Baghouse Filtration Products 

Verification Status Report. Osaka, Japan. The Association of Powder Process Industry and 

Engineering, Japan (APPIE) October 29, 2001. 

Mc Kenna, J.D.; Mycock, J.C.; Practical Implications of ETV for Fine Particle Control,

The Air & Waste Association Annual Meeting June 23, 2004 

McKenna, J. D.: A New Tool for Improving Control of Fine Particle Emissions. Institute of Electrical 

and Electronics Engineers, Roanoke Va. September 21, 2006 

McKenna, J. D.: Filter Media Selection for Coal Fired Plants, McIlvaine Company Hot Topic Hour

October 16, 2008 

WORKSHOPS 

Drexel University, 2001 Olin Workshop On The Environment, Philadelphia, PA “Environmental 

Technology for Particulate Emission Control” 

Rheinhold Environmental 2002 ESP/FF Roundtable & Expo, Dallas, TX “Fabric Filter Application & 

Selection” 

PETROBRAS 2007 Seminar on Atmospheric Emissions, Rio de Janeiro, Brazil “Air Shed 

Management PM10/PM2.5/0zone” 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 61 November 2, 2010 

James P. Norton, P.E. 

Mr. Norton is a Principal Engineer and President of Norton Engineering Consultants, Inc. (NEC), 

which he founded in 1993. He has 30+ years experience in the petroleum process, specialty 

chemicals, lubricants, energy and environmental fields. 

Mr. Norton has had a broad range of experience in petroleum refining and petrochemicals 

including: 

• Fired heaters, boilers, CO boilers, incinerators, burners, and other solids, liquid and gas 

fueled combustion equipment and ancillary systems, 

• Process development for reactive extrusion, polymer processing, and selective non-catalytic 

NOx reduction processes, 

• Polymer Processing specialist (synthetic rubber and silanes), 

• Process Design – solution polymerization plants, synthetic rubber dewatering and drying 

facilities, direct polymer devolatilization systems, reactive extrusion systems for polymer 

modification, lube blending, lubricant additive manufacturing, environmental control 

systems (SOx, NOx, PM, HAPs), fired heaters, steam generators, heat exchangers, 

pneumatic conveying systems, wet gas scrubbing systems, water treating facilities, offsites/utilities, steam boilers, waste heat recovery facilities, etc. 

• Planning – lube blending, lubricant additives, flue gas desulfurization and particulate control 

systems, environmental control facilities for polymer manufacturing plants, water slurry 

polymer finishing, direct devolatilization of solution polymers, solvent recovery and 

purification systems, delayed coker debottlenecking, fluid coker, and flexicoker projects. 

Selected Career Highlights 

1993 to Present: Norton Engineering Consultants, Inc., Boonton, NJ 

• Refinery steam system optimization and boiler upgrade project planning, design and 

execution support (HOVENSA – 2008) 

• Refinery boiler house ULNB conversion, economizer replacement and flue gas recirculation 

system design (Sunoco – 2008) 

• Replacement Atmospheric and Vacuum Crude Heater designs (CO Heaters on FCCU) 

(Valero – 2007-08) 

• Naptha Hydrotreater and Catalytic Reformer Heater UNLB Conversion Project Design 

(ConocoPhillips 2007-08). 

• CO Boiler upgrade design and field supervision (ConocoPhillips – 2007 - 2009). 

• Crude Unit Heater SIS System Design & Start-up (ConocoPhillips – 2007-08). 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 62 November 2, 2010 

• FCCU/FCU Emissions Control Project consulting (Valero – 2001-2007). 

• FCC CO Boiler evaluation for installation of emissions control facilities (ConocoPhillips – 

2007). 

• FCCU wet gas scrubbing system troubleshooting (ConocoPhillips – 2007). 

• FCCU wet gas scrubbing project design review (ConocoPhillips – 2007). 

• FCCU wet scrubbing system project assistance (cold-eyes reviews) (ConocoPhillips – 

2007). 

• NHT fired reboiler design and design of retrofit SIS system for NHT pre-heater furnace 

(Valero - 2006) 

• Troubleshooting – LABSORB Regenerative Scrubbing System (Valero – 2006) 

• Consulting – FCCU scrubber expansions (Various Clients - 2002, 2006, 2007) 

• Lead Investigator for US DOE Advanced Fired Heater Development Project (2001 – 2005) 

• Assessment of commercial technologies for the direct devolatilization of solution polymers 

(EP/EPDM) (2004-05) 

• Solution polymer blending and devolatilization facilities for toll processor (2003) 

• Jet Ejector Venturi Wet Gas Scrubbing System Design including assessment of regenerator 

overhead circuit including flue gas expander and back pressuring existing CO Boiler – EM 

R&S (2000-2001) 

• Flue Gas Desulfurization Technology Evaluation – EM R&S (1999) 

• Wet Gas Scrubbing System Designs – ExxonMobil Licensees (1996, 1997, 2001, 2004) 

• FCCU Regenerator O/H Modifications for Electrostatic Precipitator Installation On-the-Run 

– Ultramar Diamond Shamrock (Quebec, 1996) 

• Turnaround support and operations consulting for combined FCCU and FCU CC Boiler 

• Boiler fired petroleum coke, waste CO gas from the FCCU and FCU and had supplemental 

RFG capability. (Alberta - 1994) 

• Lubricant Additives Plant (solution polymerization facility) – Process Design and Planning 

(Infineum France SA, 1999 – 2000) 

• Start-up support for SRP section of client’s synthetic rubber plant (1995). 

• Dispersants Plant - Process, Environmental Control and Offsites Design (ECC, 1995 – 

1996) 

• Lubricants Blending Plant Operations Consulting and Design Services (EUSA, Continuing) 

• Hazardous Material Control Systems Development and Implementation (Lockheed Martin 

Aerospace, 1994 – 1996) 

• Boiler Emissions Control Technology Selection (SOx & PM) for Bitumen Fired Steam 

Generators – IOR (2001) 

• Reactive Extrusion Process Development - ExxonMobil Chemical / Dow Corning (1999 - 

2000) 

• CO Heater Encon & SCR NOx Control Study – Exxon Benicia Refinery (1992). 

• SNCR DeNOx Utility Boiler Design – Exxon Research & Engineering (1993-94) 

• ExxonMobil WGS Licensing Support & Process Development (1996 -2005) 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 63 November 2, 2010 

1990 – 1993 Martech Industries, Inc. 

• Process Development for Continuous Polymer Dissolving Process – Exxon Chemical 

Polymers Group. 

• Operations and Maintenance Consulting – Exxon, Bayonne Lubricants Plant 

• Selective Non-catalytic NOx Reduction Facilities Design – Exxon Research & Engineering. 

• Lead Designer – Steam Plant Upgrade Project – Exxon, Pittsburgh PA 

• Various Process Planning Activities for client’s worldwide petroleum and petrochemical 

operations (Exxon Chemical & Exxon Res & Engr). 

1984 – 1990 Exxon Chemical Company, Polymers Group 

• Elastomer Extrusion Specialist 

• Elastomer drying and direct devolatilization process development engineer 

• Elastomers manufacturing support 

• Process designer & planner for solution and slurry elastomer manufacturing facilities – 

primary focus on product finishing and stripping areas of plant. 

1978 – 1984 Exxon Research & Engineering Co. 

• CO Boiler Specialist – Design, Troubleshooting & Operations Consulting 

• Steam Cracker & Steam Reformed Design 

• Fired Heater, Steam Generator and Incinerator Designs 

• Technology Commercialization – Materials of Construction, Burners, Air Preheat Systems, 

Advanced Fired heater and Boiler Controls, Energy Conservation Strategies. 

• Plant Automation including Artificial Intelligence Systems Design and Testing 

• Synthetic Fuels Planning, Process Development and Design 

• Start-up Support and Plant Troubleshooting. 

• Hydrocracker Heater Rebuild. 

• Delayed Coking Heater Troubleshooting 

• Delayed Coker Operations Consulting and Cycle Time Optimization 

Process Simulation Tools 

• PRO II (Proprietary and Commercial Thermodynamic Packages) 

• HYSYS (Continuous and Batch Simulations) 

• HEXTRAN 

• Proprietary Plant and Process Evaluation Tools 
Final Staff Report – Part 2 Appendix B – Consultants’ Biographies 

___________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part II - 64 November 2, 2010 

Education 

• Bachelor of Mechanical Engineering, Manhattan College, Bronx NY, 1978 

• Master of Mechanical Engineering, Manhattan College, Bronx NY, 1981 

Professional Accreditation 

• Licensed Professional Engineer – State of New Jersey – GE28615 (1983) 

Patents & Publications 

• US Patent (1984) Steam Generating Solids Cooler for Spent Shale, Hot Catalyst and Fluid 

Coke. 

• US Patent (1988) Method for Agglomerating and Dewatering Polymeric Materials 

• US Patent (1991) Centrifugal Solids Cooler for Pneumatic Conveying Systems 

• Patent Pending (2007) – Advanced Fired Heater 

• Patent Pending (2007) – Zero Plugging Slurry Distribution Headers and Onstream Descaling 

System