1

Kelly, Shaheerah

From: Eric Albright [ealbright@environcorp.com]

Sent: Friday, September 13, 2013 3:25 PM

To: Kelly, Shaheerah

Cc: Rios, Gerardo; Christenson, Kara; Shane Young; George Emmerson

Subject: SPI-Anderson - Responses to Requests for Additional Information

Attachments: Response to August 29 information request - final.pdf

Shaheerah:

Attached are responses to the request for additional information received by email on August 29 concerning Sierra

Pacific Industry’s cogeneration project (PSD Permit Number SAC 12‐01), as well as additional requests made during

teleconferences involving Region 9, SPI, and ENVIRON on August 27 and September 11.

Thanks, and, if you have any questions, please call me at the number below.

Eric

Eric Albright, PE | Senior Manager

ENVIRON International Corporation

19020 33rd Avenue W, Suite 310 | Lynnwood, WA 98036 

T: +1 425 412 1804 | F: +1 425 412 1840 | M: +1 206 909 0591

ealbright@environcorp.com

From: Kelly, Shaheerah [mailto:Kelly.Shaheerah@epa.gov] 

Sent: Wednesday, September 11, 2013 4:01 PM 

To: Eric Albright; Shane Young 

Cc: Rios, Gerardo; Christenson, Kara; Dave Brown 

Subject: FW: SPI Anderson 

  

Shane and Eric,

Thanks for taking the time to discuss the SPI GHG application with me. As a follow up to our discussion, below are the

items SPI will be providing to EPA. Please let me know if you have any clarifications.

1. Description of the existing kilns at facility.

2. Cost effectiveness data in $/ton for the catalytic oxidation.

3. Description of boiler features and measures that will be taken to ensure “good boiler design, good combustion

practices, and efficient operation,” which is provided as a baseline in step 1 of the GHG BACT analysis.

It would be helpful if you could send a response this week. Please let me know if you need more time than this.

Regards,

************************************ 

Shaheerah Kelly

U.S. Environmental Protection Agency, Region 9 

Permits Office, Air Division 
2

San Francisco, CA 94105 

Phone: 415-947-4156 

Fax: 415-947-3579 

Email: kelly.shaheerah@epa.gov

From: Dave Brown [mailto:DBrown@spi-ind.com] 

Sent: Tuesday, September 10, 2013 2:48 PM 

To: Kelly, Shaheerah 

Cc: Rios, Gerardo; Shane Young; Sloan, William M.; Dave Dun; Christenson, Kara 

Subject: SPI Anderson - Change in primary contact - FYI

  

Shaheerah – We’re making a change in primary contact for SPI related to the Anderson PSD permit – please use Shane

Young as the primary SPI contact moving forward.  Below is Shane’s contact information

  

Shane Young

Facility Manager

Sierra Pacific Industries – Anderson Division

19758 Riverside Avenue

PO Box 10939

Anderson, CA  96007

530‐378‐8350 ph

530‐378‐8360 fax

swyoung@spi‐ind.com

  

Thank you,

  

David C. Brown, PE

Environmental Affairs & Compliance Manager

Sierra Pacific Industries

19794 Riverside Avenue

Redding, CA 96049-6028

(530) 378-8179

(530) 378-8139 fax

(530) 391-7650 cell

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reply to email@environcorp.com and immediately delete all copies of the message. 
In an email received by SPI on August 29, 2013 you requested additional information to assist your 

ongoing review of the GHG BACT analysis submitted in support of SPI’s permit to construct and operate 

a new biomass-fired cogeneration unit at the existing facility in Anderson, California. 

We have repeated your information requests in italics below; each request is followed by a response. 

1. The analysis states that manufacturers of FBBs indicated that their designs were not appropriate for 

use when the boiler would be operated at loads less than 50 percent of the rated capacity (i.e., in 

“turndown” mode). Although “turndown” mode is not defined, SPI’s January 23, 2012 letter to EPA 

generally describes “turndown” mode as periods when steam is generated at rates as low as 20 

percent maximum load. Please provide more details regarding the information you obtained from 

manufacturers. 

In the context of combustion unit operation, the term “turndown” is sometimes used to describe 

when the unit is operated at less than maximum capacity. Combustion unit manufacturers typically 

assign a nominal capacity rating (sometimes called a “nameplate” rating, because the rating is 

stamped or printed on a plate, along with the manufacturer name and model information, that is 

affixed to the unit), which could be expressed in terms of heat input, fueling rate, or, in the case of a 

boiler, steam production rate. Operating the combustion unit or boiler at anything less than this 

nominal rating would be considered a “turndown” mode. For example, a boiler is rated by the 

manufacturer to produce 250 thousand pounds of steam per hour (klb/hr) when operated at a given 

heat input and/or fueling rate. If the rate of heat input or fuel delivery is reduced, the boiler will 

produce less steam. That lower rate of steam production, divided by the manufacturer’s nominal 

capacity for steam production, is the “turndown ratio.” If the example boiler were producing steam 

at a rate of 50 klb/hr, that would be a turndown ratio of 20 percent (50 / 250 x 100% = 20%, or a 

“5:1 ratio”). 

Manufacturers of fluidized bed boilers (FBBs) were contacted and asked if they could provide an FBB 

that would be able to operate in the same manner as the proposed stoker boiler for the Anderson 

facility, and as described in the AAQIR and Project Description (see September 2012 AAQIR at pg. 

12). The operational parameters provided to the FBB manufacturers were based on the operational 

requirements of the project, including the turndown capability required in the governing PPA for the 

project that the advance notification time for turndowns is only 60 minutes. These parameters are: 

a maximum steam generating capacity of 250,000 lb/hr (@ 900 °F & 1,250 psig), with the capability 

to operate at least as low as 50,000 lb/hr, and to be able to accommodate this load reduction (i.e., 

100% to 20% of full load) within 1 hour. We have received responses from three manufacturers. The 

first response, from Energy Products of Idaho (EPI), was obtained in January 2012 using a project 

description that did not include the responsiveness requirement, because, at the time, that 

requirement was not known. More recently, two responses have been received from Factory Sales 

and Engineering (FSE – who supplies both stoker and FBB design boilers), and Metso. The three 

responses (see attached) indicate that each manufacturer cannot provide an FBB that would fulfill 
the operational parameters for the project. The specifications of the proposed stoker boiler design, 

as well as a letter confirming the turndown performance of the design, are also attached. 

2. The analysis states that a FBB is not appropriate for use at loads less than 50% of capacity (turn 

down mode) because the turndown makes FBBs “impractical.” Please describe the technical 

impracticalities of a FBB. 

The NSR Workshop Manual states that there are two components to determining whether an 

undemonstrated technology is feasible for a specific application: “availability” and “applicability.” A 

technology is considered “available” if it can be obtained by the applicant through commercial 

channels, and is otherwise available within the common sense meaning of the term. An available 

technology is “applicable” if it can reasonably be installed and operated on the emission unit under 

consideration. SPI has diligently searched and found no instances of FBB units used at comparable 

wood products manufacturing facilities to provide steam to lumber dry kilns operating under the 

scenarios that are called for in this project. As a result, implementing an FBB would be an 

undemonstrated technology for use as the proposed cogeneration unit.1

 FBB units are certainly 

commercially available, but, according to FBB manufacturers, the available FBB designs are not 

capable of meeting the use proposed. 

In their responses to our inquiries (see attached), the FBB manufacturers indicated that operation of 

the boiler would be unstable at 60 or 70 percent turndown. Instability results because, when the 

load is reduced to that extent, the pressure drop across the bed is not sufficient to maintain proper 

mixing of the bed. When the bed is not properly mixed, local hot spots are formed and ash removal 

efficiency decreases. The combination of hot spots and higher quantities of ash in the bed, can 

result in ash melting and become sintered2

, leading to widespread agglomeration, which can result 

in bed de-fluidization, and interruption of boiler operation.3

Sintering of fluidized bed ash is typically caused by alkali metals (mainly potassium), which form 

compounds with relatively low melting points. All biomass fuels contain these alkali metals in 

varying concentrations, and their presence means that maintaining a uniform bed temperature to 

avoid localized hot spots is critical to reliable FBB operation.4

 

 

1

 U.S. Environmental Protection Agency (USEPA), “New Source Review Workshop Manual: Prevention of Significant 

Deterioration and Nonattainment Area Permitting.” Draft, October 1990. Page B.17. 

http://www.epa.gov/NSR/ttnnsr01/gen/wkshpman.pdf 2

 Sintering is when atoms in individual particles of a powdery substance diffuse across the particle boundaries, 

fusing the particles together, and creating a larger particle 

3

 Simeon Oka, “Fluidized Bed Combustion.” Marcel Dekker, Inc., 2004. Page 407. - 

http://203.158.253.140/media/e-Book/Engineer/Power%20Plant/Fluidized%20Bed%20Combustion/ 4

 A. van der Drift and A. Olsen, “Conversion of Biomass, Prediction and Solution Methods for Ash Agglomeration 

and Related Problems, Final Report.” Contract number JOR3-95-0079 in the framework of the JOULE III 

programme. November 1999. Page 9. 
It would be “impractical” for SPI to employ an FBB that lacked a 20 to 50 percent turndown 

capability as the proposed cogeneration unit. When operational, the proposed cogeneration unit 

will be the only source of steam at SPI’s Anderson facility. It will provide steam to the turbine to 

generate electricity, and to the kilns to produce dried lumber. The majority of the lumber produced 

by the facility is kiln-dried; undried, or “green,” lumber makes up only a small portion of total 

production,5

 and demand is largely restricted to Douglas fir. As a result, it is imperative that the 

cogeneration unit continue to provide steam to the kiln, regardless of PG&E’s power production 

requirements. 

If the cogeneration unit was not capable of operating at low loads (i.e., 20 to 50 percent of full load), 

the kilns would have to cease operation any time the power production demand by PG&E decreased 

significantly, or the turbine was not operating. In 2012, the steam turbine generator at the SPI 

facility in Lincoln, California required repairs, and was not operational for 8 weeks. Because the 

stoker boiler at that facility was capable of producing steam at low loads, the kilns were able to 

operate the entire time that the turbine was being repaired. Had the boiler not been capable of 

operating at low loads, those 8 weeks of dried lumber production, and the associated revenue, 

would have been lost. 

3. The analysis states that SPI’s unit will be expected to achieve significant load changes (e.g., 100% to 

50%) within a short period of time (e.g., 1 hour) and FBB’s cannot accommodate abrupt load 

changes. However, SPI’s January 23, 2012 letter states that “because PG&E will provide advance 

notice of power needs, it is unlikely that the steam demand variations will require quick responses 

from the boiler; the variability will be on a day-to-day basis, rather than hour -to-hour.” Please clarify 

whether how often load changes will be expected to occur (i.e., hourly, daily, or weekly, etc). 

At the time the January 23, 2012 letter was finalized, the power purchase agreement (PPA) between 

SPI and Pacific Gas & Electric (PG&E) was still being negotiated. When signed on August 9, 2012, the 

PPA required SPI to ramp power production down to the point where the turbine is generating little, 

if any electricity, or pay a significant penalty for each megawatt-hour (MWh) delivered to the grid 

when PG&E does not want it. As noted previously, the advance notification period for production 

rampdown is only 60 minutes in the PPA. This requirement and associated penalty is included in the 

PPA by PG&E to facilitate managing the electrical grid. It is impossible to predict, in advance, the 

frequency or magnitude of the load changes required by PG&E. 

Aside from PPA obligations, steam load demand by the kilns will typically range from 30,000 lb/hr to 

a maximum of 80,000 lb/hr, depending on drying schedules and lumber species. When a kiln charge 

completes the drying cycle, steam flow to that kiln is stopped. It is possible for multiple kilns to finish 

at the same time, which, if it coincided with a PG&E curtailment notice, could result in a substantial 

decrease in overall steam demand over a short period. 

 

5

 In 2012, 6.3 percent of all lumber produced at the Anderson facility was sold undried; in 2013, the fraction to 

date is 9.7 percent. 
4. North Springfield Sustainable Energy Project in Vermont and WE Energies in Wisconsin are two 

recently permitted cogeneration projects that will construct or have constructed biomass-fired FBBs. 

It is not clear how these projects are distinguishable from SPI’s cogeneration operation. Please 

provide a comparison of these projects and the SPI Anderson project and how these FBB facilities are 

distinguishable SPI’S cogeneration operation. 

When constructed and operating, the North Springfield Sustainable Energy Project in North 

Springfield, Vermont will be a wood-fired electrical generating station. The GHG BACT analysis 

prepared for the project (which does not consider boiler design) indicates that “recovery of low 

grade heat” will be used “to produce hot water for a thermal loop in the North Springfield Industrial 

Park.” Although not discussed in the Technical Support Document for Permit to Construct generated 

by the Vermont Agency of Natural Resources Department of Environmental Conservation, Air 

Pollution Control Division, facilities such as the North Springfield Industrial Park typically have 

existing means for generating hot water, and the proposed thermal loop would augment the 

existing system. The consequences associated with the “low grade heat” from the North Springfield 

Energy Project being unavailable to the North Springfield Industrial Park hot water system would be 

limited to a return to the current hot water system status, and associated cost of operation. The 

project does not operate lumber dry kilns, or provide process steam of any real consequence, and is 

not subject to operational considerations regarding influences on steam load demand external to 

power production as is the Anderson facility. At this point, SPI has searched for, but not found, any 

available information regarding whether the project has a PPA, so potential steam demand 

fluctuations imposed on the project by a power purchaser are unknown. 

The We Energies project, to be installed and operated adjacent to the Domtar Mill in Rothschild, 

Wisconsin, would include an 800 million British thermal unit per hour (MMBtu/hr) biomass-fired, 

circulating fluidized bed boiler, and also a 350 MMBtu/hr natural gas-fired package boiler. Steam 

from the biomass-fired boiler will be used to generate electricity, and to provide process steam to 

the Domtar Mill. During periods when the biomass-fired boiler is not available, the natural gas-fired 

package boiler will be used to provide process steam to the Domtar Mill, allowing it to continue 

operation. Natural gas-fired boilers can be started relatively quickly, and the inclusion of such a unit 

in the We Energies project proposal decouples the Domtar Mill from the operation of the proposed 

biomass-fired boiler. In contrast, the proposed project does not contemplate the purchase, 

installation and use of an additional fossil-fuel based boiler, and the existing biomass-fired boiler at 

the facility will no longer operate, having been decomissioned after the new cogeneration unit is 

operational. 

5. The analysis states the following: “The power purchase agreement associated with supplying 

generated electricity to the grid requires a high level of availability; the electrical generation 

commitments for this unit are not compatible with accommodating an exploratory or innovative 

application of existing technology.” There are other facilities that use biomass-fired FBBs. Please 

clarify why SPI believes FBB is an “exploratory or innovative application of existing technology.” 
Based on the responses solicited from FBB manufacturers, and the fact that there is no existing 

example of an FBB that is operated as proposed for this project (i.e., with the capability to operate 

at 20 to 50 percent of full load to accommodate electrical grid fluctuations, while retaining the 

capacity to provide steam critical to the basic operation of the facility), we have concluded that 

there is currently no commercially-available FBB design that could be substituted for the stoker 

design proposed. While there are situations in which application of an FBB is appropriate, it is clear 

that the cogeneration project proposed is not an appropriate FBB application. The only possibility 

for the project to successfully employ an FBB design would require engaging in an exploratory 

research project, with potential trial and error, all towards the potentially unattainable goal of 

developing an innovative FBB design with an operational flexibility that matches that of the 

proposed stoker boiler. As with most exploratory projects that seek innovation, the cost, duration, 

and prospect of success would be uncertain. 

SPI submits, consistent with the opinions from several independent FBB manufacturers, that 

commercially available FBB designs would not be appropriate for the proposed cogeneration project at 

the Anderson facility. The proposed stoker boiler meets the operational characteristics required for the 

project, and EPA Region 9 has already determined6

 that the boiler (in conjunction with the proposed 

control systems) will achieve emission levels that represent BACT for criteria pollutants. FBBs should be 

removed from consideration as BACT for GHGs for this project, including on the grounds that it cannot 

meet the project’s operational requirements, and is therefore technically infeasible. 

During a teleconference on August 27, 2013, EPA requested additional cost information related to the 

consideration of a Carbon Capture and Storage (CCS) system as an alternative to reduce CO2 emissions 

from the project. Specifically, EPA requested a cost estimate for the transport component of a CCS 

system that would deliver CO2 from the proposed cogeneration unit to a hypothetical enhanced oil 

recovery (EOR) operation in the San Joaquin Valley. 

Using a USGS website7

, the oil field nearest to the Anderson facility is located in Brentwood, California, 

approximately 25 miles west of Stockton, California. While there is no evidence that EOR techniques are 

actually being used to develop any oil fields near Brentwood, the distance from Anderson to Brentwood, 

approximately 175 miles, was used as the length of the hypothetical CO2 transport pipeline. The CO2

flow rate was assumed to be 400,000 tons per year, and the diameter of the pipe used to construct the 

pipeline was assumed to be 6 inches.8

 

6

 U.S. Environmental Protection Agency, Region IX, “Statement of Basis and Ambient Air Quality Impact Report, 

Sierra Pacific Industries-Anderson PSD Permit Number SAC 12-01,” September 2012. Pages 11 to 22 – 

http://www.epa.gov/region9/air/permit/pdf/sierrapac/2012-10-12-proposed-spi-anderson-aaqir.pdf 7

 Natural Oil and Gas Seeps in California – http://walrus.wr.usgs.gov/seeps/ca_seeps.html 8

 Diameter estimated from Massachusetts Institute of Technology CO2 Pipeline Transport Cost Estimation, June 

2009, Figure 2.1 and Table 1 – http://e40-hjh-server1.mit.edu/energylab/wikka.php?wakka=MIT 
Capital and operating costs were calculated using formulas provided in a DOE/NETL document.9

 Pipeline 

costs are broken down into three categories, as follows: 

 Pipeline/Transport Cost – includes pipeline materials, direct labor, indirect costs, and right of 

way acquisition as a function of pipeline length and diameter. 

 Related Capital Expenditures – includes a CO2 surge tank and pipeline control system. 

 O&M Costs – based on a cost per mile of pipeline per year operated. 

Table 1 is a summary of the capital costs associated with constructing the hypothetical pipeline 

described above. At a total capital cost of almost $109 million, the pipeline would be more than twice 

the cost of the cogeneration project (estimated to be between $40 and $45 million). Table 2 summarizes 

the total annualized cost of the pipeline, which would be almost $11 million per year. The cost of the 

transportation component of a CCS system, ignoring the cost of the CO2 capture system, which are also 

considerable, and the costs associated with storage and monitoring, which are not insignificant, suggest 

that, at this time, implementation of a CCS system is not a cost-effective GHG reduction alternative for 

this project. 

 

9

 “Quality Guidelines for Energy System Studies: Carbon Dioxide Transport and Storage Costs in NETL Studies”, 

DOE/NETL-2013/1614, March 2013 – http://www.netl.doe.gov/energyanalyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf 
Table 1. Capital Cost of CO2 Pipeline to Deliver CO2 from Anderson, California to Hypothetical EOR Operation in Brentwood, California 

Cost Type Inputs & Units1 Cost 

Pipeline Capital Costs 

Materials Diameter (inches), 

Length (miles) $70,350 + $2.01 x L x (330.5 x D2

 + 686.7 x D + 26,960) $ 15,210,392 

Labor Diameter (inches), 

Length (miles) $371,850 + $2.01 x L x (343.2 x D2

 + 2,074 x D + 170,013) $ 68,998,850 

Miscellaneous Diameter (inches), 

Length (miles) $147,250 + $1.55 x L x (8,417 x D + 7,234) $ 15,831,408 

Right of Way Diameter (inches), 

Length (miles) $51,200 + $1.28 x L x (577 x D + 29,788) $ 7,510,266 

Other Capital Costs 

CO2 Surge Tank $ $ 1,244,724 

 Pipeline Control 

System $ $ 111,907 

Total Capital Cost 

$ 108,907,547 

1 Pipeline diameter was assumed to be 6 inches based on estimation from Massachusetts Institute of Technology CO2 Pipeline Transport Cost 

Estimation, June 2009, Figure 2.1 and Table 1 – http://e40-hjh-server1.mit.edu/energylab/wikka.php?wakka=MIT; pipeline length was assumed 

to be 175 miles, based on distance to the oilfield closest to the project, which is in Brentwood, California. 

 
Table 2. Annual Cost of CO2 Pipeline to Deliver CO2 from Anderson, California to Hypothetical EOR Operation in Brentwood, California 

Cost Type Inputs & Units1 Cost 

Annualized Capital Cost 

Total Capital Cost 

Total Capital Cost (TCC, $),

Interest Rate (i) 

Period (n) 

TCC x (1+i)n $10,280,102

Annual O&M Cost 

 Fixed O&M Length (miles) $8,632 x L $ 1,512,844

Total Annualized Cost 

$11,792,946 

1 Total capital costs were annualized based on an assumed equipment life of 20 years, and a 7% interest rate; pipeline length was assumed to be 

175 miles, based on distance to the oilfield closest to the project, which is in Brentwood, California. 
During a teleconference on September 11, 2013, and in a follow-up email, you requested the following 

additional information: 

1. Description of the existing kilns at facility. 

There are eight steam-heated, double-track, lumber dry kilns at the facility. Seven of the kilns 

are 105 feet in length, and the eighth kiln is 120 feet in length. 

2. Cost effectiveness data in $/ton for the assessment of catalytic oxidation in Step 4 of the GHG 

BACT analysis. 

Table A-3 of the BACT analysis submitted with the permit application indicates that a catalytic 

oxidation system would have an annualized cost of approximately $2,380,000 assuming 20 year 

life and 7 percent interest. Table 5-1 of the GHG BACT analysis document indicates that a 

catalytic oxidation system would be expected to reduce GHG emissions from the project by 

approximately 7,000 tons per year (433,000 – 426,000 = 7,000). Dividing the annualized cost by 

the reduction in GHG emissions results in a cost effectiveness of $340 per ton ($2,380,000 / 

7,000 = $340). For comparison, the cost effectiveness of carbon capture and sequestration (CCS) 

systems as applied to large (i.e., 500 MW) pulverized coal and natural-gas fired combined cycle 

power plants calculated by NETL/DOE is between $68 and $89 per ton of CO2e avoided10, and, 

even though CCS applied to a biomass plant is thought to be twice as expensive as when applied 

to a coal-fired power plant11, an oxidation catalyst is still comparatively expensive. 

3. Description of boiler features and measures that will be taken to ensure “good boiler design, 

good combustion practices, and efficient operation,” which is provided as a baseline in step 1 of 

the GHG BACT analysis. 

The proposed cogeneration unit is an efficient, state-of-the-art, air-cooled, reciprocating stepgrate stoker design incorporating under-grate air zones where air flow is controlled to combust 

and gasify the fuel in the primary combustion chamber. The gases from the fuel then pass from 

the primary combustion chamber, through an orifice to a secondary combustion chamber where 

additional over-fire air is injected to complete combustion of the gases produced in the primary 

combustion chamber. The secondary combustion chamber is designed with a cyclonic choke 

that creates a highly turbulent region where the gases from the primary combustion chamber 

and secondary air are completely mixed, which promotes complete combustion. A combustion 

air fan provides preheated air to the under-gate air zones in the primary chamber, as well as 

over-fire air in the secondary chamber. 

 

10 National Energy Technology Laboratory (NETL), “Cost and Performance Baseline for Fossil Energy Plants – 

Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2,” November 2010. DOE/NETL-2010/1397. 

Page 300. http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_Rev2.pdf 11 International E (IEA), “IEA Energy Technology Essentials: CO2 Capture & Storage,” December 2006. Page 3. 

http://www.iea.org/techno/essentials1.pdf 
The cogeneration unit and the steam turbine generator will be monitored by trained operators 

at all times to ensure that maximum efficiency is achieved at all times. Operation of the 

cogeneration unit and steam turbine will incorporate sound maintenance practices 

recommended by the manufacturer, to ensure that the facility operates in an efficient and 

reliable manner on an ongoing basis. 
1

Eric Albright

From: Kent Pope <kmpope@energyproducts.com>

Sent: Wednesday, January 11, 2012 3:32 PM

To: Eric Albright

Cc: Eric Wesselman

Subject: EPI Boiler performance question

Hi Eric and thanks for the email. EPI, now owned by Outotec, does provide fluidized bed energy systems capable of 

producing process or superheated steam. Our typical systems range in size from 20,000 lb/hr up to 500,000 lb/hr in a 

single boiler. Our fuels list features hundreds of different fuels and certainly wood, urban and agricultural fuels are on 

the list. EPI has also been a leader in setting the standards for low emissions. The desire to turn down from 250,000 

lb/hr to 50,000 lb/hr is something that you might try to do with a gas fired boiler but solid fuel systems do not typically 

have that kind of turndown without dropping the superheat temperature. 

 

I will ask Eric Wesselman of our group give you a call to further discuss this project. 

 

Thanks again for thinking of us. 

 

 

Kent Pope 

Director, Business Development 

Outotec Energy Products

3568 W Industrial Loop 

Coeur d'Alene, Idaho 83815 

(208)765-1611 

(208)765-0503 fax 

kmpope@energyproducts.com

www.energyproducts.com 

>>> Eric Albright <ealbright@environcorp.com> 1/11/2012 2:17 PM >>> 

I’m working for a client that has asked me to look into the feasibility of using a biomass-fired fluidized bed boiler to 

provide process steam as well as steam to run a turbine and generate electricity. Maximum capacity would be 250,000 

lb/hr of steam, with the capability to operate at least as low as 50,000 lb/hr for extended periods (i.e., days or 

weeks). The majority of the fuel would be clean, wet (~50% MC) wood fuel, blended with a maximum of 20% urban 

and/or agricultural wastes. Can you provide such a boiler, and, if yes, can you provide references of installed examples 

of boilers you have provided that operate in this way? The overall project would be permitted through the U.S. EPA, 

and the exhaust would have to meet best available control technology requirements. 

Thanks, and please call me if you have any questions. 

Eric 

___________________________________________________________

Eric Albright, PE | Senior Manager

ENVIRON International Corporation | www.environcorp.com | ealbright@environcorp.com

19020 33rd Ave W | Suite #310 | Lynnwood, WA 98036

main: 425.412.1800 | fax: 425.412.1840 | direct: 425.412.1804 | cell: 206.909.0591
2

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September 4, 2013

Shane Young

Sierra Pacific Industries

19758 Riverside Ave

Anderson Ca. 96007

P 530-378-8356

C 530-604-0025

swyoung@spi-ind.com

Reference: Bubbling Fluid Bed Turndown

Dear Mr. Young:

In regards to the particular boiler operation at your mill, i.e. the necessity to operate at

loads as low as 20% MCR to continually run and follow dry kiln schedules,

electrical output, or run in island mode

the correct application for this technology.

Typically, stable BFB operation is not practical below 60%MCR due to the reduction in

fluidizing velocity within the bed as air is reduced for lower turndown

As a background to our company, we feel that we are technology neutral with respect to

combustion as we offer fixed grate stokers, reciprocating grates, vibrating grates, BFB,

and CFB options based on operational, fuel, and emission requirements.

Please let us know if you have any questions or required additional information.

Very truly yours,

FSE Energy

Chris Culpepper, P.E.

Vice President, Business Development

Bubbling Fluid Bed Turndown

In regards to the particular boiler operation at your mill, i.e. the necessity to operate at

20% MCR to continually run and follow dry kiln schedules,

r run in island mode; FSE feels that a bubbling fluid bed boiler is not

the correct application for this technology.

BFB operation is not practical below 60%MCR due to the reduction in

fluidizing velocity within the bed as air is reduced for lower turndown.

As a background to our company, we feel that we are technology neutral with respect to

combustion as we offer fixed grate stokers, reciprocating grates, vibrating grates, BFB,

and CFB options based on operational, fuel, and emission requirements.

Please let us know if you have any questions or required additional information.

Development

In regards to the particular boiler operation at your mill, i.e. the necessity to operate at

20% MCR to continually run and follow dry kiln schedules, reduce

FSE feels that a bubbling fluid bed boiler is not

BFB operation is not practical below 60%MCR due to the reduction in

As a background to our company, we feel that we are technology neutral with respect to

combustion as we offer fixed grate stokers, reciprocating grates, vibrating grates, BFB,

Please let us know if you have any questions or required additional information.
1

Eric Albright

From: bill.partanen@metso.com

Sent: Wednesday, September 04, 2013 11:57 AM

To: Eric Albright

Subject: RE: Thank you for contacting Metso

Eric, 

An 80% turndown is not possible with either a CFB or BFB. Even at a 70% turndown ratio, bed temperature stabilization 

may be required using an auxiliary fuel. If the kiln requires 30% of the total steam flow, a turbine that could produce 30 

Mw of electricity at 170,000 PPH would require a boiler that operates at very high temperatures and pressures. Bringing 

the boiler down to 20% output in an hour would require blowing off steam which would waste a lot of feedwater and 

associated chemicals. It sounds to me like you are looking for a wood boiler that can operate like a gas turbine and 

HRSG. 

Bill 

From: Eric Albright <ealbright@environcorp.com> To: "bill.partanen@metso.com" <bill.partanen@metso.com>, 

Date: 09/04/2013 02:10 PM Subject: RE: Thank you for contacting Metso 

Turbine would provide approimately 30 MW. 

Maximum load to kilns is about 80 klb steam, and minimum load is about 20klb. 

Ramping back up to maximum load within an hour would be desirable. 

Thanks for your help, and please let me know if you have any more questions. 

Eric 

Sent from my Android phone using TouchDown (www.nitrodesk.com) 

-----Original Message----- 

From: bill.partanen@metso.com [bill.partanen@metso.com]

Received: Wednesday, 04 Sep 2013, 10:46am

To: Eric Albright [ealbright@environcorp.com]

Subject: Thank you for contacting Metso 

What is the desired power output from the turbine? What is the minimum and 

maximum steam load to the kilns and the drying cycle? You stated that the 

boiler must be able do go from 250,000 lb/hr to 50,000 lb/hr within an 

hour. Does it need to ramp up to 250,00o lb/hr in the same timeframe? 

This message contains information that may be confidential, privileged or otherwise protected by law from 

disclosure. It is intended for the exclusive use of the Addressee(s). Unless you are the addressee or authorized 

agent of the addressee, you may not review, copy, distribute or disclose to anyone the message or any 
2

information contained within. If you have received this message in error, please contact the sender by electronic 

reply to email@environcorp.com and immediately delete all copies of the message. 
Sierra Pacific

5-May-10

ESTIMATED PERFORMANCE DATA:

Boiler Capacity (lb/hr) 250,000

Operating Condition

Steam Pressure (psig) 1,250

Steam Temperature (deg F +- 10deg F) 950

Drum Operating Pressure (psig) 1,320

Feedwater Temperature from DA (deg F) 340

Boiler Blowdown (%) <1

Dry Bulb Temperature (deg F) 80

Relative Humidity (%) 30

Site Elevation (ft. ASL) 430

Excess Air @ Grate (%) -30

Excess Air @ AH (%) 40

Combustion Air (lb/hr) 435,623

Flue Gas Flow @ AH Outlet (lb/hr) 527,595

Flue Gas Flow @ AH Outlet (acfm) 177,672

Flue Gas Temp @ AH Outlet (deg F) 300

H20 in Flue Gas (%-wet basis by wt) 14.6

Fuel Type Wood

Fuel Moisture Content (%) 50

Fuel HHV (Btu/lb) dry basis 8,688

Fuel Input (lb/hr) 94,195

Heat Input (MMBtu/hr) HHV 409.2

Unburned Carbon Loss (%)1

Boiler Efficiency (%) 70.0

Ash Produced (lb/hr) 2,185

Unburned Carbon (lb/hr) 471

Total Residue (lb/hr) 2,656

Uncontrolled Emissions:

• CO (lb/MMBtu HHV) 0.23

• NOx (lb/MMBtu HHV) 0.23

• PM (lb/MMBtu HHV) 0.45

Motor Sizing:

• FD Fan (hp) 500

• ID Fan (hp) 800

• FW Pump (hp) 800
2000 McFarland 400 Blvd., Alpharetta, GA 30004

Ph. 770-226-6394 email:jim.teaford@dieffenbacheratl.com

1

Sept. 10, 2013

Mr. Shane Young

Sierra Pacific Industries

19758 Riverside Ave

Anderson Ca. 96007

Dear Shane:

This letter is being presented to describe why Sierra Pacific Industries made the proper 

application of the Dieffenbacher Wood Fired boiler system to your new steam generation 

project.

The Dieffenbacher boiler system is designed with the ability to operate at low load 

conditions which you often see at sawmills. Your Sierra Pacific Industries sawmill in 

Anderson, CA, has batch-loaded lumber dry kilns. These dry kilns are periodically 

operated, shut down for unloading and re-loading and then started with widely variable 

steam demands. Additionally, being a cogeneration system that will be curtailed quickly 

by power company dispatchers, quick response to reduced loads is a necessity. 

Maintenance outages for turbine/generator equipment will also require the boiler to 

operate frequently at reduced loads of less than 50% of the boiler nameplate capacity. 

This Sierra Pacific Industries boiler application requires a boiler that can swing quickly 

and is able to operate at reduced output loads of 20%, or less, of the boiler maximum 

output. The Dieffenbacher boiler can do this because of its unique design which has fuel 

metering capable of 10 to 1 turndown and combustion air control capable of 8 to 1 

turndown. This unique combination of furnace grate design and control of air and fuel 

allows the biomass boiler to operate for this batch dry kiln system very efficiently. 

If you have any questions, or need any additional information, don’t hesitate to contact 

us.

Sincerely,

James Teaford, VP

Cc/Peter Lynch, Larry Frazier