1



## Review of the Biomass Stoker CO Limits and Suggestions for Revis ions

Introduction

Some, but not all, companies operating boilers that are in the biomass stoker subcategory have concerns with the CO limit of 490 ppm at 3 % O 2 . C ompliance with this limit will

be determined with an annual Method 10 test with three runs of minimum one hour duration. It is widely acknowledged that biomass boilers have highly variable CO

emission rates during normal operations, especially boilers that are load

- following.

Alt hough the annual compliance test will most likely be carried out when the boiler is operating in a steady state condition at near full load (so that the operating load restriction of 110% would not limit boiler firing rates over the subsequent 12 months)

, there are still

concerns that the 3

- hour average CO levels observed during an annual test will on some occasion exceed the 490 ppm limit. Occasional exceedances would be expected to occur

even on boilers where measures have been taken to minimize CO emis sions.

Additionally, t here are a number of biomass stoker boilers with CO CEMS installed to meet a permitting requirement. These units will not be able to demonstrate continuous compliance with the 490 ppm limit, essentially a 3

- hour average limit, give n the widely known variability of CO concentrations from stoker design boilers. Companies operating

such boilers would like EPA to set an alternative CO limit for an averaging time much longer than 3 hours and base compliance on CEMS data. The forest pro duct industry supports EPA’s decision not to require CO CEMS as a compliance requirement in the Boiler MACT given the availability of other compliance demonstration options, however, giv ing facilities compliance options and alternative limits will provide the flexibility

needed to a cc ount for the wide range of boiler operations, fuel mixes and equipment configurations.

The new source limit for the biomass stoker subcategory is 160 ppm at 3% O 2 , with compliance to be determined by an annual Method 10 stack test. This limit will be even more challenging to consistently meet. EPA has predicted no new biomass boilers subject to the Boiler MACT rule will be built in the future. T hi s is not a realistic prediction, as currently there are a number of proposed bi omass boilers in the permitting

process

.



### Previous Dialogue with EPA

Over the last three months, industry representatives have discussed these concerns with EPA technical staff and management. There appears to be some willingness on the part

of EPA to consider adjusting the current CO limit for biomass stokers and to devel op an alternative limit for stokers equipped with CO CEMS. EPA feel s such revisions cannot be justified by the CO data they presently have, and therefore have challenged industry

stakeholders to provide additional data to support their desired changes to the limits.

EPA set a July 15 deadline for receiving additional data due to the extremely ambitious2

schedule set by EPA management . The schedule calls for issu ance of a proposal for changes to the Boiler MACT and CISWI rules by October 31, 2011 and finaliz ing it by April 30, 2012

.

Given this schedule, EPA has been urging use of existing data rather than generation of

new data. They feel constrained legally to only consider additional data from the small group of boilers in the biomass stoker MAC T floor for CO , i.e. the so

- called best performers

. EPA’s current list of best performers in the biomass stoker subcategory is shown in Table 1. EPA Method 10 test data, as reported by the facilities and then adjusted by EPA to account for potential inst rumental inaccuracies, were used to select the 12 best performers (12% of the 96 biomass stoker boilers in EPA’s emissions

database with Method 10 data). To qualify as a best performer, at least 90% of the boiler heat input during the test had to come fro m biomass.

There are problems with this list of top performers. First, there are several units in the stoker subcategory with an identical test result of 210 ppm, which is not the reported test

value but rather a “maximum CO measurement error for bioma ss” number, as described in the ERG memo “Incorporating Measurement Error in Reported Carbon Monoxide and Total Hydrocarbon Data.” Only 6 of 13 units with a 210 ppm value were included in the top 12%; these seem to have been selected based on alphabetica l order of the facility ID.

This i s arbitrary since 13 units were assigned an identical value. Second, six of the units apparently do not belong in the stoker subcategory. Third, the inclusion of WIFlambeauRiverPaper was based on a test conducted when t he boiler was firing 100% coal. Fourth, the MSGPNewAugusta test was conducted while the boiler was firing more than 10% natural gas in addition to biomass.

EPA stated this list of top performers is subject to change depending on what new information they receive by July 15. Additional Method 10 tests from these or other biomass stokers, corrections to previously submitted test data, corrections of errors in boiler design information, and changing instructions from the Office of Resource

Conservation and Recovery about what alternative fuels will be solid wastes, could alter

the current list of best performers

.

EPA was informed that none of biomass stoker boilers on their current list of top CO performers had a CO CEMS, so any additional data for these units would have to come from new tests in the coming months. Industry representatives indicated a testing

prog ram involving installation of temporary CEMS on two or more of these boilers for a period of at least four months was under consideration. EPA noted the data from such a testing effort would not be available until March 1 at the earliest. This would req uire

issuance o f a Notice of Data Availability. Further, a placeholder for an alternative, longer

- term CO standard would need to be adequately described in the October proposal to address any notice and comment issues that might arise since the data w ould be

submitted long after the close of the comment period on the proposed changes to the

Boiler MACT rule. EPA would then need to amend the final rule if the data supported3

Table 1

. Lowest CO

- Emitting Stokers Burning Biomass

Facility ID Minimum

Test Average Data Type Rank In Top

12%? NCASI Comments

MILPCSagola 68 ET 1 YES 2008 test. Has 6 additional tests for CO between 1997 and 2010. Company states

unit has not been operated at full load due to PM limits.

MNAndersonCorpBayport 93 ET 2 YES 2008 test. Additional tests in 2007 (163 ppmv) and 2008 (120 ppmv) on common stack with EU620 and EU621. Reportedly a suspension burner, not a stoker.

MNAndersonCorpBayport 99.5 ET 3 YES 2008 test. Additional tests in 2007 (163 ppmv) and 2008 (120 ppmv ) on common stack with EU620 and EU621. Reportedly a suspension burner, not a stoker.

WVWeyerhaeuserBuckhannon 100 ET 4 YES 2005 test with reported average of 23 ppmv. Additional test from 2010 with average of 238 ppmv.

WIFlambeauRiverPaper 108 ET 5 YES Test conducted with 100% coal. Other tests conducted with 100% biomass, but results all above 210 ppmv.

MSGPNewAugusta 130 ET 6 YES 2007 test; reported average 102 ppmv. Test report shows natural gas provided more than 10% of the heat input during the CO test runs. 122 days (10/1/10

- 1/31/11) of continuous CO data available from temporary instrument while firing over 90%

biomass. ARWestFraserHuttig 210 ET 7 YES 2005 test; reported average 65 ppmv

IDChilcoLakeSawmill 210 ET 8 YES 2005 test; reported average 51 ppmv IDRileyCreekLumber 210 ET 9 YES 2003 test; reported average 161 ppmv INConsolidatedGrainandBarge 210 ET 10 YES 2008 test on common stack for units P17B and P17C; reported average 87 ppmv INConsolidatedGrainandBarge 210 ET 11 YES 2008 test on common stack for units P17B and P17C; reported average 87 ppmv MNWeyerhaeuserIronton 210 ET 12 YES Company says boiler should be classified as a fuel cell; mill currently idle.

MSHoodBeaumont 210 ET 13 NO 2006 test with reported average of 12 8 ppmv. Also a 2008 test with average of 422

ppmv. Additional test conducted in 2010, reported average of 598 ppm

.

MSIPVicksburg 210 ET 14 NO 2007 test; reported average 198 ppmv. Test report shows natural gas and TDF provided more than 10% of heat input during test. Also tests in 2005, 2006 with averages of 313, 298, and 367 ppmv.

MSShuqualakLumber 210 ET 15 NO 2006 test with reported value of 122 ppmv ; appears to be a single run

. Boiler not of stoker design

– package unit; tangentially fired watertube

. OHAkronThermalEnergy 210 ET 16 NO 2007 test; reported average of 129 ppmv.

ORStimsonLumberForestGrove 210 ET 17 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006

test. Company states the 3 b oilers are pile burners, not stokers.

ORStimsonLumberForestGrove 210 ET 18 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006

test. Company states the 3 b oilers are pile burners, not stokers.

ORStimsonLumberForestGrove 210 ET 19 NO 2007 test on common stack for 3 boilers burning resinated wood. Also have 2006

test. Company states the 3 b oilers are pile burners, not stokers. MNDESPHansONyman EU007 215 ET 20 NO 2007 test.4

changes to the CO limits for biomass stoker boilers or establishment of a longer term CO limit for units with existing CEMS.

When queried about the use of existing CO CEMS data to determine if boilers other than those on EPA’s current list might be best performers, EPA staff opined there would have to be a significant portion of 3

- hour averages that were at or below those of the best performers (which would presumably be an average of 210 ppm at 3% O 2 or less considering the current group of best performers). In addition, the boiler would have to be firing at least 90% biomass during the 3

- hr periods when CO was less than 210 pp m. The CO and O 2 CEMS would have to meet the QA/QC provisions of EPA Performance Specifications 4 and 3, respectively, for the data to be acceptable to EPA.



### Analyses and Data t o Support Revision of the 3

- Hour Limit s

Prior to undertaking any analyses, boilers in the top 12% must be identified. As described in the January 2011 revised MACT floor analysis ERG memorandum, there

were 96 biomass boilers in the “stoker/ sloped grate/ other” subcategory with Method 10

CO tests presumably conducted when at least 90% of the heat input came from biomass. Using the lowest Method 10 test for each of these units, the units were ranked from lowest to highest and the 12 units with the lowest test results (as adjusted by EPA to

account for instrument accuracy) were selected as being in the MACT floor for this subcategory (12% of 96 units with data). If the Method 10 test was conducted on a stack serving two or more stoker boilers, EPA treated the test result as representing the

emissio ns from each boiler.

The top 12 units are list ed in Table 1. We believe the following units do not belong in the stoker/sloped grate/other subcategory :

**•** MNAndersonCorpBayport (2 boilers ; both should be in suspension subcategory )

**•** MNWeyerhaeuserIronton (s hould be in fuel cell subcategory ; company informed EPA and ERG of this fact in May 2011 ) WIFlambeauRiverPaper should be removed since their lowest test was conducted while burning 100% coal. MSGPNewAugusta should be removed since less than 90% of the

hea t input came from biomass during the only CO test.

Although not on the top 12 list, the three units at ORStimsonLumberForestGrove should be in the Dutch oven/suspension subcategory. T he MSIPVicksburg boiler should be

removed since the 2007 test was conducted when less than 90% of the boiler heat input came from biomass. The 2008 survey response from this facility inadvertently omitted TDF from the list of fuels burned during the various CO tests. C orrection s are being

submitted to EPA.

If th e six non

- stoker boilers are removed from the subcategory, and MS IPVicksburg is removed from the boilers that have CO test data while firing over 90% biomass, it would

leave 8 9 units having Method 10 test data and thus there would only be 11 units in the t op 12%. With the removal of MS GPNewAugusta , there would only be 10 remaining boilers

in Table 1 with a CO test having an average of 210 ppm or less

. According to the ERG5

floor memorandum, the next lowest average was 215 ppm for the MNDESPHansONyman EU007 boiler, so this unit would have to be added to the best performer list.

Effect of Revised List of Top Performers

Using only Method 10 test data contained in the EPA emissions test database for the revised group of 1 1 biomass stoker units having at least one Method 10 test a verage of

215 ppm or less, and using the statistical procedures described in the January 2011 revised MACT floor analysis ERG memorandum, the 99.9% UPL would be 4 74 ppm at
3% O 2 (log normal distribution with Bhaumik and Gi b b ons correction )

. Note this calculation includes an additional test for MSHoodBeaumont (2008)

.

Effect of Additional Method 10 Tests for Best Performers

NCASI has learned there are additional Method 10 tests not in the EPA emissions

database for three of the remaining best performers . There are six additional tests for LPCSagola (1997, 2000, 2002, 2005 {two} , and 2011 compliance tests)

, one for WVWeyerhaeuserBuckhannon (2010 compliance test)

, and one for MSHoodBeaumont (2010 compliance test)

. Incorpor ating these tests into the 99.9% UPL calculations described in the previous section gives a 99.9% UPL of 7 20 ppm

.

Since LPCSagola is the best performer in the subcategory, the additional Method 10 tests on this unit will alter the new source limit for the subcategory. Incorporating these tests

into the 99.9% UPL calculations for log normal distribution with Bhaumik and Gibbons

corr ection gives a 99.9% UPL of 823 ppm.



### Effect of Statistical Procedures

In calculating the 99.9% UPL which was the basis for the 490 ppm limit, EPA used

individual Method 10 runs from 16 different tests conducted on the 12 best performing

boilers. Each of the 48 runs was treated as an independent observation. When a Method 10 test is conducted, the three runs are generally conducted within a three to four hour period and thus should not be viewed as producing independent samples

– the three 1

- hr

runs w ill be highly auto

- correlated. It would be more appropriate to treat each Method 10 test average as an independent sample (refer to NCASI discussion paper on this topic submitted separately)

. If the 99.9% UPL is recalculated using the 16 test means as independent observations , the value would be 619 ppm at 3% O 2 using a log

- normal

distribution.

Using the revised list of 11 best performers, t he effect of using test averages instead of individual runs as independent observations would result in a 9 9.9% UPL of 6 52 ppm if only data currently in the EPA database were used, and 9 65 ppm if the additional tests for MILPCSagola

, WVWeyerhaeuserBuckhannon

, and MSHoodBeaumont were included.

T he new source limit using all data from MILPCSagola would be 1303 ppm.6

Effect of Adjusting CO Values to Account for Measurement Errors

A January 2011 ERG memorandum ( Incorporating Measurement Error in Reported Carbon Monoxide and Total Hydrocarbon Data ) stated the following:

Each test run for CO and THC was reviewed to determine if the maximum measurement error values needed to be incorporated in the data analysis for the MACT floor...If the reported emission concentration was lower than the measurement error for that test run, the default measurement err ors were used in lieu of the reported concentration. For the units in Appendix A that had test reports available to extract a test

- specific calibration span, the measurement error for this test was compared to the reported test run concentrations. For al l remaining test data, the reported test run concentrations were compared to the appropriate default measurement error... Default values for biomass boiler CO tests were 210 ppm for tests conducted through May 2008 and 160 ppm for tests conducted af ter May 2 008.

Application of this procedure to Method 10 test data from biomass boilers resulted in nine boilers being assigned the default value of 210 ppm for all test runs. One unit was assigned a value of 100 ppm for its three runs (although a review of the 2 005 test report for this unit indicates the CO span gas concentration was 100 ppm rather than 1000 ppm)

, and another 130 ppm for its three runs (see Table 1).

Having so many runs with identical values affected the standard deviation calculated by

EPA fo r the test data for the 12 best performing units. This fact undermines EPA’s claim that the variability in CO emissions was accounted for in the 99.9% UPL calculation

since the standard deviation derived from run

- by

- run concentrations was used . EPA staff promised to look into this situation and consult with their statisticians . They hoped they could get the stack test reports for the best performing units and determine the actual span gas concentrations used for the Method 10 tests so that the default va lues could be replaced. However, this would not adequately address the variability issue since the actual CO concentrations would still be unknown for many test runs.

Effect of Additional CO CEMS Data from Non

- Best Performers

In the dialogue with EPA, EPA suggested CEMS data from non

- best performers might be

considered in revising the CO limit for biomass stokers if (1) the CEMS for CO and O 2 met EPA QA/QC criteria, e.g. PS

- 4 and PS

- 3, annual RATAs, periodic calibration and

dri ft tests, (2) a significant fraction of the 3

- hr block averages were at or below the concentrations measured in Method 10 tests by the best performers, and (3) at least 90% of the boiler heat input came from biomass during each 3

- hr average.

There are at least 26 stoker boilers that burn biomass in the forest products industry with CO CEMS. Although these boilers would likely be in the biomass subcategory because 10% or more of their annual heat input comes from biomass, most do not continuously

get over 90% of their heat input from biomass. Some combust sludge, TDF, resinated wood, urban hog fuel, or OCC rejects, and the status of such materials under the solid7

waste definition rule is uncertain. Also, it is not known how many of monitors satisfy

PS

- 4 a nd other QA/QC requirements. NCASI is gathering more information about these

monitors to see what data meeting EPA’s three criteria can be obtained.

Outside of the forest products industry, there are at least 18 biomass stoker units operated by electri city generating firms with CO CEMS. The majority of the boilers are at facilities which are not major sources of hazardous air pollutants , or the boilers burn secondary biomass materials that may be classified as solid wastes. We understand EPA

will not u se any data from boilers that will be subject to GACT or CISWI standards to set MACT limits. NCASI is trying to determine which of these units will be subject to the

MACT standards and would have CEMS data meeting EPA’s three criteria.

To date, NCASI has obtained two sets of CO CEMS data that should meet EPA’s criteria. These data are described and analyzed in the next two paragraphs t o illustrate how such CEMS information might be employed for revising the current 490 ppm standard for this subcategor y.

One year (1

- 1

- 2010 to 12

- 31

- 2010) of hourly CO CEMS data was obtained for the WABoiseWallula boiler that burned hog fuel and natural gas ( 78 % biomass annual average). This is a 1979 vintage stationary grate, mass feed stoker unit that had an

overfir e air system installed about 5 years ago. Located at a kraft pulp and paper mill, i t
is a load

- following boiler with a steaming capacity of 235,000 lb/hr on hog fuel. The CO limit is 500 ppm at 7% O 2 , rolling 12 month average. The CO and O 2 stack monito rs are located after a wet ESP. After eliminating hourly averages corresponding to startup/shutdown conditions and CEMS malfunctions (about 3. 3 % of the hourly averages), three

- hour block averages were computed. Of the 28 33 3

- hr average blocks,

1 23 (or 4.3 %) corresponded to periods when biomass firing exceeded 90% of total heat input (rest gas), and 91 of these 1 23 (or 7 4 %) were less than 210 ppm at 3% O 2

. The

calculated 99.9% UPL value of all 28 33 3

- hour block averages was 81 0 ppm at 3% O 2 (using log n ormal distribution with Bhaumik and Gibbons correction). The 99.9 percentile value ( 4 th highest of the block averages) was 9 79 ppm, and the highest was 1022 ppm.

One year (6

- 1

- 2010 to 5

- 31

- 2011) of hourly CO CEMS data was obtained for the

Genesee Pow er Station boiler that burned 100% biomass at all times. The biomass usually included a small amount of used animal bedding (wood shavings with manure). This is a 1995 vintage tangentially fired stoker with a vibrating grate. It has a heat input capacit y of 523 x10 6 Btu/hr and electricity generating capacity of 36 MW. During this period, electrical output fluctuated between 10 and 36 MW, generally on a diurnal basis.

Add

- on controls are an ESP and SNCR. The CO limit is 0.35 lb/10 6 Btu, 24

- hr rolling

average. Nearly 9. 8 % of the hourly values were eliminated (periods of startup/shutdown

or no steam output, and CEMS malfunction s and calibrations ) before computing three

hour block averages. Of the 26 57 3

- hr average blocks, 17 21 (or 64 .8%) corresponded to periods when CO emissions were less than 210 ppm at 3% O 2

. The 99.9% UPL value of

all 26 57 3

- hour block averages was 7 30 ppm at 3% O 2 (using log normal distribution8

with Bhaumik and Gibbons correction). The 99.9 percentile value ( 4 th highest of the block averages) was 972 ppm, and the highest was 1 539 ppm.

Besides these two sets of CO CEMS data, four months of continuous CO data from a temporary CEMS were obtained for the MSGPNewAugusta boiler for the period October 1, 2010 to Jan uary 31, 2011. (As noted earlier, the test result that put this boiler in the best performer group was conducted when less than 90% of the boiler heat input came from biomass.) The monitor was not certified. Minute

- by

- minute data were reduced to

1

- hr av erages and corrected to 3% oxygen. A small amount of data (0.4%) corresponding to periods of instrument malfunction and calibration conditions were eliminated before computing three

- hour block averages. During the entire four month period, with the

excep tion of a two hour period when 100% gas was fired, over 90% of boiler heat input on an hourly basis came from biomass. The 99.9% UPL value of the 3

- hour block averages (960 points) was 735 ppm at 3% O 2 assuming the data were normally distributed, but sinc e the data were not normally distributed, the 99.9% UPL value of the log

- normally transformed data was estimated and found to be 928 ppm at 3% O 2 ( with

the Bhaumik

- Gibbons correction ). About 14% of the 3

- hr block averages were less than 210 ppm, the max imum level for the current (and revised) group of best performing

biomass stokers.

The CEMS data illustrate a 3

- hr stack test for CO on a biomass boiler could fall anywhere on a very broad spectrum of concentrations that occur over the course of normal op erations. Even though EPA’s CO limit attempts to account for this known variability by being set at the 99.9% UPL based on individual run data from best performing units, the CEMS data from these three boilers, which could be considered as having similar CO emissions to those of the best performers, show a 3

- hr average limit of 490 ppm would be exceeded 3.2% of the time at Genesee, 5.5% of the time at Wallula, and about 10% of the time at New Augusta. Thus, a random 3

- hr test would have a finite probability of being above 490 ppm

. The results suggest EPA’s current database and statistical procedures have not resulted in a 3

- hr average limit that could be achieved by the best performers during every stack test they will conduc t.