1111 Nineteenth Street, NW, Suite 800 ▪ Washington, DC 20036

202 463-2700 Fax: 202 463-2785 ▪ www.afandpa.org 222 Catoctin Circle SE, Suite 201 ▪ Leesburg, VA 20176

202-463-2766 Fax: 202-463-2791 ▪ www.awc.org 

### November 16, 2012

The Honorable Lisa P. Jackson

Administrator

U.S. Environmental Protection Agency Ariel Rios Building 1200 Pennsylvania Ave, N.W. Washington, D.C. 20460

Petition for Reconsideration of 40 C.F.R. Part 98 Subparts C and AA; Petition for Rulemaking To Revise 40 C.F.R. Part 98 Subparts C and AA; Request for Correction Under Information Quality Act

Dear Administrator Jackson:

By this letter the American Forest & Paper Association (AF&PA) and the American Wood Council (AWC) petition EPA, pursuant to section 307(d)(7)(B) of the Clean Air Act, for reconsideration and re vision of 40 C.F.R. Part 98 (Mandatory Greenhouse Gas Reporting) Subpart AA (Pulp and Paper Manufacturing), specifically,

the default emission factors fo r estimating emissions of methane and nitrous oxide from pulp mill chemical recovery furnaces. AF &PA and AWC also petition for reconsideration and revision of 40 C.F.R. Part 98 Subpart C (General Stationary Fuel Combustion Sources), specifically, the default emission factors for estimating emissions of methane

and nitrous oxide from combustion of solid biom ass fuels. These provisions were first promulgated in a rule published at 74 Fed. Reg. 56,260 (Oct. 30, 2009).

Reconsideration pursuant to CAA sect ion 307(d)(7)(B) is appropriate because newly available information—stack testing of greenhouse gas emissi ons from pulp mill recovery furnaces and biomass-fired bo ilers—demonstrate that the default emission factors for these units in Subparts AA and C substantially overstat e typical emissions

from these sources. 1 

### This information was not available during the rulemaking 2 

### , and it

is of central relevance to the outcome of the rulemaking, because it goes to the accuracy of the greenhouse gas emission in formation that the Mandatory Greenhouse

1 See Appendix A to this petition, Methane (CH 4 ) and Nitrous Oxide (N 2 0) Emissions from Biomass-Fired Boilers and Recovery Furnaces. Technical Bulletin No. 998, and Appendix B to this petition, containing letters from the National Council for Air and Stream Improvement to Paul Noe, AF&PA and Robert Glowinski, AWC.

2 See Appendix B.

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Gas Reporting rule is intended to collect and it demonstrates the need for different

emission factors from those contained in t hat rule. Under these circumstances, CAA section 307(d)(7)(B) requires EPA to re consider these emission factors (“the

Administrator shall convene a proceeding for reconsi deration of the rule” (emphasis added)). In addition, AF&PA and AWC believe that there is other information, which arguably might not meet the criteria for a petit ion for reconsideration, but which supports revision of Subparts AA and C of the Mandatory Greenhouse Gas Reporting rule nonetheless and therefore is appr opriately presented in a petition for rulemaking, as authorized by 5 U.S.C. § 553(e) . AF&PA and AWC therefore ask that EPA consider the following as both a petition for reconsiderat ion under CAA section 307(d)(7)(B) and, to

the extent EPA believes that the information presented does not require reconsideration under CAA section 307(d)(7)(B), then as a pet ition for rulemaking under 5 U.S.C. § 553(e). 3



### Summary of Requested Changes to the Mandatory Greenhouse Gas Reporting

Rule

Currently, 40 C.F.R. § 98.273 directs pulp and paper mills subject to the rule to estimate methane (CH 4 

### ) and nitrous oxide (N 2 

### O) emissions from chemical recovery furnaces using default emission factors, spec ified in Table AA-1 to 40 C.F.R. Part 98 Subpart AA, of 0.030 and 0.005 kg/mmBtu HHV, respectively. AF&PA and AWC petition EPA to reconsider and revise T able AA-1 to replace those default emission

factors with emission factors of 0.0019 kg/mmBtu HHV for CH 4 

### and 0.00042 kg/mmBtu

HHV for N 2 

### O. The emission factors cu rrently in the regulations are significantly higher than indicated by recovery furnace emission test data, including extensive recentlycompleted stack testing provided with this pet ition, and they are higher as well than emission factors used by various ot her governmental and nongovernmental organizations. The current EPA emission fact ors therefore result in a substantial overstatement of pulp and paper industry CH 4 

### and N 2 

### O emissions from recovery

furnaces.

For that reason, AF&PA and AWC also request, pursuant to the Information Quality Act, that EPA correct its database and greenhouse gas emission inventory reports to reflect the fact that a more accurate estimate of recovery furnace emissions is approximately an order of m agnitude lower than the emissions estimates that EPA

3 Because CAA section 307(b)(1) provides for ju dicial review of this type of EPA action only through a petition for review, filed in the court of appeals within 60 days after new information becomes available, AF&PA and AWC also plan to file today a petition for review of the Mandatory Greenhouse Gas Reporting rule, pursuant to CAA section 307(b)(1) and Rule 15(a) of the Federal Rules of Appellate Procedure, in the U.S. Court of Appeals for the District of

Columbia Circuit.

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required pulp mills to submit under the Mandatory Greenhouse Gas Reporting regulation.

Similarly, the emission fa ctors in Table C-2 to 40 C.F.R. Part 98 Subpart C, which facilities burning solid biomass fuels are directed by 40 C.F.R. § 98.33(c) to use

to estimate annual CH 4 

### and N 2 

### O emissions, substantially ov erstate emissions measured in numerous stack tests of a variety of wood- and wood-residue-fired boilers. AF&PA and AWC therefore petition EPA to reconsider and revise Table C-2 of 40 C.F.R. Part 98 Subpart C to replace the emission factor s for combustion of “Biomass Fuels—Solid” of 0.032 kg CH 4 

### and 0.0042 kg N 2 

### O per mmBtu with emi ssion factors of 0.0049 kg/mmBtu for CH 4 

### and 0.0019 kg/mmBtu for N 2 

### O.

Finally, AF&PA and AWC seek revision of Table AA-2 of 40 C.F.R. Part 98 Subpart AA to clarify what pulp mills are supposed to report for lime kiln emissions (other than CH 4 

### emissions from kilns burning natur al gas). Formatting problems with

that table have created and will create confusion unless it is revised.

(Please note that this petition for rulema king and request for correction of existing databases does not address questions of whether and in what fashion CO 2 

### , CH 4 

### , and

N 2 

### O emissions from burning black liquor or solid biomass fuels should be counted as emissions of greenhouse gases, in light of the fact that the carbon contained in emissions from combustion of black liquor and wood and wood re sidue is part of the carbon cycle in which carbon dioxide is re moved from the atmosphere through the process of photosynthesis. Th is petition concerns only how to estimate the mass of

CH 4 

### and N 2 

### O emitted from combustion of black li quor in pulp mill recovery furnaces, combustion of solid biomass, and oper ation of lime kilns at pulp mills.)

New Emission Factors Would Be tter Reflect Stack Test Data

Combustion of Pulping Liquor in Recovery Furnaces

The CH 4 

### and N 2 

### O emission factors for pulp mill chemical recovery furnaces in Table AA-1 to 40 C.F.R. Part 98 Subpart AA we re selected from what we believe to be the most complete compilation of GHG emissi on rate estimates for pulp and paper mills: Calculation Tools for Estimating Greenhouse Ga s Emissions from Pulp and Paper Mills,

Version 1.1 (July 8, 2005), prepared by the Na tional Council for Air and Stream Improvement, Inc. (NCASI), in associat ion with the Climate Change Working Group of

the International Council of Forest and P aper Associations, for the World Resources

Institute and World Business Council for Sustainable Development Greenhouse Gas Protocol Initiative (the “WRI/WBCSD Greenhous e Gas Protocol Calculation Tools”).

That document collected information on recovery furnace emissions of CH 4 

### and N 2 

### O,

and emission factors used to estimate thos e emissions, from Finland, Sweden, and Japan and from the European Environment Agency. See WRI/WBCSD Greenhouse

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Gas Protocol Calculation Tools p. 29 Table 8. It recommended that recovery furnace GHG emissions be estimated using em ission factors of 2.5 kg/TJ CH 4 

### and 2 kg/TJ N 2 

### O, reflecting the median of emission fact ors derived from those sources. Id . at 28-29.

For the Mandatory Greenhouse Gas Repor ting Rule, however, EPA used the highest emission factor for both CH 4 

### and N 2 

### O suggested by any of the references it cited (converted from kg/TJ to kg/MMBtu), rather than us ing the median values. The emission factors EPA chose, from a 2004 report by the Swedish Environmental Protection Agency, were 5-10 times higher than the emission rates collected from Finland and Japan, and for CH 4 

### the emission factor of 30 kg /TJ EPA used is almost two times higher than even the high end of the ra nge of emissions repo rted by the European Environment Agency. See id . Table 8 and June 16, 2011 e-mail from Sean P. Hogan, EPA Office of Atmospheric Programs, to Rhea Hale, AF&PA (repr oduced in Appendix C to this petition). 4



### Similarly, the 30 kg of CH 4 

### per TJ emission factor EPA used to set the reporting requirement for recovery furnaces in the Mandatory Greenhouse Gas Reporting Rule is 10 times higher than the default emission fact or for black liquor combustion derived for the latest inventory reporting guidance i ssued by the Intergovernmental Panel on Climate Change (3 kg/TJ), and it is almost twic e as high as the highest end of the range of the emissions reported in that guidance (1-18 kg/TJ). See 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 2, p. 2.19 Table 2.3 (available online athttp://www.ipccnggip.iges.or.jp/public/2006g l/pdf/2_Volume2/V2_2_Ch2_Sta tionary_Combustion.pdf). Likewise, the emission factor EPA used in the Mandatory Greenhouse Gas Reporting

Rule for N 2 

### O, derived from an assumed emission rate of 5 kg N 2 

### O per TJ, is more than

double the default emission factor for bla ck liquor combustion in the latest IPCC guidance. See id . It is important to note that EPA was an active participant in IPCC’s development of recommended emissions fact ors, and yet in the Mandatory Greenhouse Gas Reporting Rule EPA ignored the results of that process and chos e emission factors much higher than the emissi on factors recommended by IPCC.

4 Significantly, the pulp and paper industry has not been able to obtain any justification for the very high Swedish EPA emission factors that E PA chose as the basis for the default emission factors for recovery furnaces in the Mandatory Greenhouse Gas Reporting Rule. Inquiries by NCASI and by AF&PA members with operations in Sweden have been unsuccessful in finding the source of that emission factor, and it appear s that the Swedish EPA official responsible for preparing the cited report is now deceased. This lack of documentation for emission factors that are much higher than the emission factors reported by others is further justification for not choosing those values for purposes of estimating annual U.S. emissions from pulp and paper

mills.

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The current default CH 4 

### and N 2 

### O emission factors for burning spent pulping liquor in the Mandatory Greenhouse Gas Reporti ng Rule thus are based on an outlier, with the express purpose of ov erstating those emissions so that the emission factors

would be “conservative.” S ee June 16, 2011 e-mail from Hogan. As such, they almost certainly result in a large overstatement of annual CH 4 

### and N 2 

### O emissions from pulp mill chemical recovery furnaces. The emi ssion factors AF&PA and AWC seek in this petition for rulemaking would provide a much better estimate of thos e emissions, as the IPCC and others have recognized.

The compilation of emissions dat a and emissions factors in the 2005

WRI/WBCSD Greenhouse Gas Protocol Calculation Tools reflect relatively few recovery

furnace stack tests. A recent NCASI review of subsequent literature indicated that there

still is a dearth of accurate and direct emission m easurements of CH 4 

### and N 2 

### O emissions from recovery furnaces, espec ially those located in North America. 5 

### Because of the growing interest in CH 4 

### and N 2 

### O emissions, NCASI conducted what may be the most extensive testing to date of recovery furnace CH 4 

### and N 2 

### O emissions, reported in the enclosed NCASI Technical Bulletin, Methane (CH 4 

### ) and Nitrous Oxide (N 2 

### O) Emissions from Biomass-fired Boilers and Recovery Furnaces (September 2012) (“Technical Bulletin 998”), Appendix A to this pet ition. That report, released September 18, 2012, is the basis for this petition for reconsideration.

NCASI obtained data on CH 4 

### and N 2 

### O emissions from five direct contact evaporator (DCE) recovery furnaces and th ree non-direct-contact evaporator (non-DCE or NDCE) recovery furnaces at six kraft pulp mills, measured using Fourier transform infrared spectroscopy. (Recovery furnaces designed with direct-contact evaporation of weak black liquor and those with non-direct contact evaporators were expected to have

somewhat different CH 4 

### and N 2 

### O emissions, which was confirmed by the NCASI stack testing.) Multiple runs on multiple days we re conducted at each recovery furnace, often over two or more days.

In this extensive testing, both the mean and the median CH 4 

### and N 2 

### O emissions from recovery furnaces were far less than the default emission fact ors in the Mandatory Greenhouse Gas Reporting Rule, Table AA-1 to 40 C.F.R. Part 98 Subpart AA. See

Technical Bulletin 998 pp. 23, 27-28.

Because the default recovery furnace emission factors in the Mandatory Greenhouse Gas Reporting Rule do not distinguish between DCE and NDCE design recovery furnaces, AF&PA and AWC asked NCA SI to analyze the data reported in

Technical Bulletin 998 to determi ne the mean emission rate for CH 4 

### and N 2 

### O for all

5 See Technical Bulletin 998, infra , pp. 1-2.

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eight of the recovery furnaces tested. T he results of that anal ysis are contained in letters from Vipin Varma of NCASI to P aul Noe of AF&PA and Robert Glowinski of AWC
dated November 8, 2012 and in cluded in Appendix B to this petition (the “Nov. 8, 2012 Letter”). That analysis allows a direct comparison of the re sults of NCASI’s study of recovery furnaces emissions to the em ission factors specified in the Mandatory Greenhouse Gas Reporting Rule, Table AA-1 to 40 C.F.R. Part 98 Subpart AA, and to those used by the IPCC and WRI/WBCSD. T hat comparison is shown in the table

below.

TABLE 1

CH 4 

### and N 2 

### O Emission Factors for Kraft Pulping Liquors, kg/mmBtu

GHG IPCC WRI/WBCSD

GHG Protocol EPA 6 

### NCASI Study

Mean (%RSD) NCASI Study Range

Methane (CH 4 

### ) 0.0030 0.0025 0.030 0.0019

(190%) 0.000042 –

0.010

Nitrous

Oxide (N2O) 0.0020 0.0020 0.005 0.00042

(68%) 0.00015 –

0.00082

Note that even the highest CH 4 

### emission rate reported fo r any of the stack tests at any of the recovery furnaces tested was still only one-third of the default emission factor contained in the Mandatory Greenhous e Gas Reporting regulations (and only

one-tenth for the more-common non-DCE re covery furnaces). See Table 1 and

Technical Bulletin 998 pp. 23, 27-28. The highest N 2 

### O emission rate reported in any of the recovery furnace stack tests was only one-sixth of EPA’s default emission factor. Id

. This further demonstrates how far the em ission factors in the Mandatory Greenhouse Gas Reporting Rule depart from actual emissions data and fr om the goal of accurately estimating total annual industry emissions.

6 Emission factors specified in 40 C.F.R. pt. 98 subpt. AA Table AA-1.

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On the basis of the ext ensive recent stack testi ng data reported in NCASI
Technical Bulletin 998, as well as the emission factors derived by other organizations discussed above, AF&PA and AWC petition for re vision of Table AA-1 to replace the default emission factors for burning kraft pulping liquor of 0.030 kg CH 4 

### per mmBtu HHV and 0.005 kg of N 2 

### O per mmBtu HHV, with emission fact ors of 0.0019 kg/mmBtu HHV

for CH 4 

### and 0.00042 kg/mmBtu HHV for N 2 

### O. 7



### Combustion of Solid Biomass Fuels

NCASI also conducted stack testing of CH 4 

### and N 2 

### O emissions at five boilers at pulp mills that fire wood (also referred to as “hogged fuel”) or bark. In some cases, the

boilers burn a combination of wood or bark and other fuel, but during the stack testing approximately 90 percent of the heat input was from bioma ss fuels at each of these five boilers. NCASI supplemented its own stack tests with an analysis of stack test data collected by EPA in connection with developm ent of Maximum Achievable Control Technology (MACT) standards for industrial, commercial, and institutional boilers and

emission standards for commercial and industr ial solid waste incineration (CISWI)

sources. NCASI identified 19 boilers tested as part of the Boiler MACT rulemaking and three boilers tested as part of the development of CISWI st andards that were deriving more than 80 percent of their heat input from wood or bark at t he time of stack testing. See description of sources tested in Technical Bulletin 998 pp. 7-12.

Technical Bulletin 998 t hus presents perhaps the most comprehensive analysis

to date of emissions from boilers burni ng solid biomass fuels. That analysis demonstrates that actual stack testing of emissions from boilers burning wood and wood residuals produces much lower measured emissions than the emission factors in Table C-2 to 40 C.F.R. Part 98 Subpart C – the factors that facilities burning solid biomass fuels are directed by 40 C.F.R. § 98.33(c) to us e to estimate annual CH 4 

### and

N 2 

### O emissions. Mean CH 4 

### emissions from the 27 boilers evaluated in Technical

Bulletin 998 were 6.5 times lower than the factor in Tabl e C-2, and the mean N 2 

### O

emissions were less than twice as much as the factor in Table C-2. See Technical

7 Note that Table AA-1, in the current vers ion of the Code of Federal Regulations, lists CH 4 and N 2 O

emission factors for North American Softwood but has blanks in the columns for those compounds for pulping liquor from the pulping of North Americ an Hardwood and other furnishes. AF&PA understands

that EPA’s intention is to use the same emission factors for CH 4 and N 2 O for pulping all types of fibers (as other organizations have), and this is reflected in EPA’s response to GHG reporting Frequently Asked Questions Q678. (Note: Q678 incorrectly states that the problem is an “e-CFR misprint” and that the table is correct in the Federal Register. In fact, the Federal Register version also had blanks in the

columns for CH 4 and N 2 O emissions except for the row for North American Softwood. See 74 Fed. Reg. 56,260, 56,465-66 (Oct. 30, 2009).) AF&PA requests that EPA fill in all of the rows in the CH 4 and N 2 O

columns of Table AA-1 with the emission factors of 0.0019 kg/mmBtu HHV for CH 4 and 0.00042 kg/mmBtu HHV, respectively, as ju stified in this petition for rulemaking. Leaving the other rows blank

makes it unclear whether and how CH 4 and N 2 O emissions are to be reported for other furnishes.

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Bulletin 998 pp. 27-28. Si gnificantly, even the highest N 2 

### O emission rate from any of

the boiler tests was less than the emission fa ctor EPA uses in Table C-2, and only two

boilers had CH 4 

### emissions (slightly) higher than t he EPA emissions factor. See

Technical Bulletin 998 pp. 22, 27-28. (Those relatively high CH 4 

### emissions at two boilers definitely are outliers, as their CH 4 

### emissions were approx imately five times larger than those observed at the other biomass-firing boilers and resulted in a mean

CH 4 

### emission rate for all 27 boilers that is over four times lar ger than the median

emission rate. See Technica l Bulletin 998 pp. 22, 24, 28.)

The stack test data present ed and analyzed in Technical Bulletin 998 show that

the emission factors for CH 4 

### and N 2 

### O mandated by 40 C.F.R. § 98.33(c) and Table C-2

result in a substantial overstatement of true emissions from boilers burning solid biomass fuels. Accordingly, AF&PA and AW C are hereby petitioning EPA to reconsider

and revise Table C-2 of 40 C.F.R. Part 98 S ubpart C to replace the emission factors for combustion of “Biomass Fuels—Solid (All f uel types listed in Table C-1)” of 0.032 kg

CH 4 

### and 0.0042 kg N 2 

### O per mmBtu, with emission fact ors of 0.0049 kg/mmBtu for CH 4 

### and 0.0019 kg/mmBtu for N 2 

### O.

The Existing EPA Emission Factors Are Inc onsistent with Their Stated Purpose

In discussing the benefits of the Mandatory Greenhouse Gas Reporting Rule, pursuant to Executive Order 12866, EPA descri bed the purpose of the rule as collecting “complete and accurate economy-wide data on fa cility-level GHG emissions,” saying it is “essential” to have “accurate and timely information on GHG emissions.” 74 Fed. Reg. at 56,369. EPA said the emissions esti mates reported pursuant to the rule would improve EPA’s “understanding of the relative emissions of specific industries,” and its “understanding of the fact ors that influence GHG emission rates.” Id . In the latest

version of U.S. Inventory of Greenhouse Gas Emissions and Sinks 1990 – 2009 (April 15, 2011), EPA 430-R-11-005, EPA clai ms that data resulting fr om the requirements of the Mandatory Greenhouse Gas Repor ting Rule that major facilities calculate and report

their emissions of CH 4 

### and N 2 

### O “will be used in future inventories to improve the emission calculations through the use of these collected higher tier methodological

data.” Id . p. 3-25.

None of these stated purposes is accomplished by using default CH 4 

### and N 2 

### O

emission factors that deliber ately and grossly overstate em issions. The best available information is that in most cases recovery furnace CH 4 

### emissions are an order of magnitude less than what pulp mills are requir ed to report under 40 C.F.R. § 98.273 and
Table AA-1, and N 2 

### O emissions are less than half of w hat the rule requires mills to report. This produces an inaccu rate picture of pulp mill CH 4 

### and N 2 

### O emissions, both

relative to other GHGs and rela tive to other sources of CH 4 

### and N 2 

### O.

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EPA’s goal of having an accurate pictur e of GHG emissions from pulp and paper mills relative to other industry sectors is not served by using emission factors that

overstate CH 4 

### and N 2 

### O emissions. Nor, obviously , do overly “conservative” CH 4 

### and

N 2 

### O estimated emission rates further EPA’s in terest in understanding what factors influence (true) GHG emission rates. EPA’s use in the Mandatory Greenhouse Gas Reporting Rule of emission factors for CH 4 

### and N 2 

### O that are much higher than the factors used by other countries, combined wit h EPA’s stated intention to use the results of reporting under that rule to “improve ” EPA’s reporting of GHG emissions to the international community, will result in inaccu rate comparisons of the GHG emissions of

the United States to t hose of other countries.

Both EPA and environmental activist groups have begun to use estimated GHG emissions as a justification fo r identifying source categories t hat they view as priorities for further GHG regulation, such as development of New Source Performance Standards. Requiring pulp and paper mills to report CH 4 

### and N 2 

### O emissions that are far greater than suggested by most emission testing creates the potential for this allocation of regulatory resources to be based on an ina ccurate estimate of GHG emissions from

that sector.

The revised CH 4 

### and N 2 

### O default emission factors that AF&PA and AWC are seeking in this petition for rulemaking wo uld alleviate these problems and would support EPA’s stated goals for the Mandatory Greenhouse Gas Reporting Rule. EPA should adopt these revised emission factors as soon as possible, so that they can be used in the next round of reporting and EPA and others can have a more-accurate picture of pulp and paper mill GHG emissions as soon as possible. EPA has recognized that it is appropriate to revise the requirements for estimating GHG emissions in the Mandatory Greenhouse Gas Reporting Rule “to better reflect new industry data and current practice.” 77 Fed. Reg. 63,538, 63,359 (Oct. 16, 2012) (granting petition for

reconsideration of emission estimation methods in 40 C.F.R. Part 98 Subpart I filed by Semiconductor Industry Association).

EPA does allow pulp mills to use site -specific emission factors for CH 4 

### and N 2 

### O for recovery furnaces. 8 

### That does not, however, alleviate the problems described above and the need for the adoption of revised emissi on factors as requested in this petition for rulemaking. First, it is not clear from the regulations whethe r mills can depart from the default emission rates in any way other t han using a site-specific HHV. See 75 Fed. Reg. at 79,127, 79,166. (The instructions for reporting GHG emissi ons from pulp and paper mills say to use “defaul t or site-specific emission factors,” see 40 C.F.R. §

8 See 75 Fed. Reg. 79,092, 79,127 (Dec. 17, 2010) and 40 C.F.R. § 98.276(e). The regulations do not appear to allow site-specific emission factors for CH 4 and N 2 O for biomass-fueled boilers, however. See 40 C.F.R. § 98.33(c).

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98.273(a)(3), but there is no further explanation of this other than the discussion of using a site-specific HHV.) But even if it is theoretically possible to rely on site-specific

emission factors rather than the default em ission factors presented in the regulations,

EPA knows that most mills wi ll use the default emission fact ors for purposes of reporting pursuant to the rule, rather than perform the costly sta ck sampling and reporting that presumably would be necessary to obt ain approval of site-specific CH 4 

### and N 2 

### O

emission factors. Cf. 40 C.F.R. § 98.53 (requirements for determining site-specific N 2 

### O emission factor for Adipic Acid Production) . The default emission factors must be revised for EPA to get accura te estimates of national CH 4 

### and N 2 

### O emissions from the pulp and paper sector.

The Proposed New Emission Factors Woul d Be Consistent with EPA Policy and

Practice

EPA obviously has used emission factors for estimating emissions in a wide variety of circumstances in the past. AF&PA and AWC are not aware of any circumstance in which EPA has estimated long-te rm emissions from individual facilities,

much less total sector emissions for the country, based on the highest emission rate tested, rather than a better estimate of aver age emissions. In fact, the concept of using averages is inherent in much of the M andatory Greenhouse Gas Reporting Rule. The

reason is obvious: A source’s total annua l emissions are equal to the number of operating days times the average emission ra te per day, not time s the maximum rate experienced on any day of the year. Likewis e, total annual emissions for an industry sector cannot be estimated by assuming that all facilities were operating for the entire year at the highest emission ra te measured at any facility.

EPA has compiled emission factors for use in Clean Air Act programs since 1972 (in a publication called AP-42 and in other databases). The EPA-OAQPS document that describes procedures for establishing emi ssion factors for AP-42 explains why the

emission factors EPA derives in other cont exts are based on average emissions over numerous sources rather than peak short-term emissions from a single source, and why it is appropriate to use such emi ssion factors for emission inventories. 9 

### EPA's emission

9 Procedures for Preparing Emission Factor Documents, November 1997, EPA-454/R-95-015, pp. 2-1 to 2-2. See also Guidance on the Recommended Procedures for Development of Emissions Factors and Use of the WebFIRE Emissions Factor Database - Review Draft, December 2010, available at http://www.epa.gov/ttn/chief/efpac/procedures/index.html, at p. 2- 1: “For most application purposes, users typicall y assume that an emissions factor represents the long-term average emissions for all facilities in a particular source category (i.e., the emissions factor represents a population average).” Id . at p. 2-2: “The emissions rate for the source, expressed in terms of mass of pollutant emitted per time unit (e.g., lb PM/hr), is calculated as the arithmetic average of the available, quality-assured test data.”

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factors development guidance does not s uggest picking the high end of a range of values, as EPA did to derive the default CH 4 

### and N 2 

### O emission factors required by the Mandatory Greenhouse Gas Reporting Rule for recovery furnaces, by picking the highest emission factor reported to be us ed or suggested by any organization.

The current default CH 4 

### and N 2 

### O emission factors for bl ack liquor combustion in Table AA-1 of the Mandatory Greenhouse Gas Reporting Rule are thus inconsistent with past EPA practice and guidance. The revis ed default emission factors requested in this petition for rulema king would correct that.

The CH 4 

### and N 2 

### O emission factors for combustion of solid biomass fuels in Table

C-2 of the Mandator y Greenhouse Gas Reporting Rule are based on emission factors

contained in the 2006 IPCC Guidelines fo r National Greenhouse Gas Inventories. Unfortunately, that document does not ex plain how those emission factors were derived, so it is unclear whether they were intended to represent average emission rates or the highest rates measured. It is clear, how ever, that the CH 4 

### emission factor

for biomass-fired boilers in Table C-2 is al most three times higher than the comparable

factor in the WRI/WBCSD Greenhouse Gas Protoc ol Calculation Tools. See Technical

Bulletin 998 at 27. This s uggests that the IPCC factor is not intended to represent a central tendency of the data but rather a high-end emission rate. As such, the IPCC

CH 4 

### emission factor (and theref ore the factor in Table C- 2 of the EPA rule) does not appear to represent an average emission rate t hat would be more appropriate for use in calculating annual U.S. emissions fr om biomass-fired boilers. The CH 4 

### emission factor proposed in this petition does.

The Proposed New Emission Factors Woul d Better Conform to the Information Quality Act and Other Directives Emphasi zing the Importance of Using the Best

Scientific Information

Congress has evidenced a strong interest in assuring that federal regulations are

based on the best scientific information availabl e. That intention is demonstrated, for example, by the Information Quality Act, Section 515(a) of the Treasury and General Government Appropriations Act for Fiscal Year 2001, P.L. 106-554; 44 U.S.C. § 3516 (notes) (“IQA”) The IQA requires that in formation disseminated by EPA be accurate, complete, reliable, and unbiased. See Office of Management and Budget, Guidelines for Ensuring and Maximizing the Quality, Object ivity, Utility and Integr ity of Information Disseminated by Federal Agencies , 67 Fed. Reg. 8452 (Feb. 22, 2002) (“OMB Guidelines”). In particular, with res pect to scientific information concerning environmental risks, EPA has recognized t hat the IQA requires EPA to present

information that is based on the best availa ble science, data, and supporting studies

and is conducted in accordance with s ound and objective scientific practices and

methods. See Guidelines for Ensuring and Maximizing the Quality, Objectivity, Utility and Integrity of Informati on Disseminated by the Environmental Protection Agency

,

### EPA Air & Radiation Docket (6102T)
Docket ID No. EPA–HQ–OAR–2007–0492 August 31, 2012 Page 12

EPA/260R-02-2008 (October 2002). Si milar directives are cont ained in Executive Order

13563 and in the President’s Memorandum fo r the Heads of Executive Departments and Agencies on ‘‘Scientific In tegrity’’ (March 9, 2009).

Directing pulp and paper mills to submit CH 4 

### and N 2 

### O annual emissions data for chemical recovery furnaces that EPA k nows are likely to gr eatly overstate true emissions, and then disseminating that inform ation to the public as EPA did in January

2012 with its first release of annual GHG em issions data reported under the Mandatory Greenhouse Gas Reporting Rule, is contrary to the IQA, the OMB Guidelines, and EPA’s own interpretation of its obligations un der the IQA, as well as directives from

President Obama. The same is true of requiring all facilities that combust wood and wood residuals to report CH 4 

### and N 2 

### O annual emissions much higher than the extensive emission testing reported in Techni cal Bulletin 998 would support. Revising

the CH 4 

### and N 2 

### O emission factors as requested in this petition would correct that deficiency for emissions reports s ubmitted after the rule is changed.

For emissions reports submitted before the emission factors are revised as requested in this petition, and for any EPA a nnual emission inventor y reports or other databases of greenhouse gas emissions, those reports and databases greatly overstate

CH 4 

### and N 2 

### O annual emissions from pulp mill recovery furnaces and biomass-fired boilers. AF&PA and AWC members are adversely affected by that overstatement of emissions, because it makes it appear as if pulp and paper mills, as well as other facilities combusting wood and wood resi duals, are larger sources of CH 4 

### and N 2 

### O than they actually are, and therefore these types of facilities may be improperly identified as targets for reductions in CH 4 

### and N 2 

### O emissions by EPA and by other governmental and nongovernmental organizations.

The information AF&PA and AWC seek to correct is the “Greenhouse Gas Reporting Program Data for Calendar Year 2010,” the availability of which was announced on January 11, 2012 and pres ented to the public at http://epa.gov/climatechange/emi ssions/ghgdata/index.html, any similar data presented for subsequent calendar years that is based on the same inaccurate emission factors

contained in Table C-2 to 40 C.F.R. Part 98 Subpart C and Tabl e AA-1 to 40 C.F.R. Part 98 Subpart AA, and any other EPA databases that rely on the same estimates of

CH 4 

### and N 2 

### O emissions reported by pulp and paper mills pursuant to the Mandatory Greenhouse Gas Reporting Rule, prior to the time that EPA revises the emission factors

for CH 4 

### and N 2 

### O as requested in the preceding petitio n for reconsideration/rulemaking.

The errors in these emissions estimate dat a, the way the data fail to comply with the IQA and OMB and EPA guidelines for informa tion quality, and the effects of the requested corrective action are all described above. AF&PA and AWC believe that it would be relatively easy for EPA to make th e requested corrections, since the estimated biomass boiler and recovery furnace CH 4 

### and N 2 

### O emissions used to generate the reports and databases for which correction is requested would only have to be adjusted

### EPA Air & Radiation Docket (6102T)
Docket ID No. EPA–HQ–OAR–2007–0492 August 31, 2012 Page 13

by multiplying those emissions by the rati o of the emission fact or requested in the foregoing petition to the emission factor c ontained in Table C-2 to 40 C.F.R. Part 98 Subpart C or Table AA-1 to 40 C. F.R. Part 98 Subpart AA.

EPA Should Correct Table AA-2 in 40 C. F.R. Part 98 Subpart AA To Eliminate Confusion Caused by the Table’s Formatting

In addition to the changes in the emissi on factors for reco very furnaces and biomass-fired boilers discussed above, AF &PA and AWC petition EPA for rulemaking to eliminate an ambiguity in the emission factors fo r kraft pulp mill lime kilns caused by the formatting of Table AA-2 in 40 C.F.R. Part 98 Subpart AA. Table AA-2 lists an emission

factor of 0.0027 for CH 4 

### emissions from lime kilns firing natural gas. The table has a

blank for N 2 

### O emissions from lime kilns firing natural gas. For all the other listed fuels, Table AA-2 provides an ellipsis or row of about 25 periods for both CH 4 

### and N 2 

### O. 10



### There is no explanation in the table or accompanying portions of the regulation as to what these ellipses signify, or how it diffe rs from the blank space in Table AA-2 for N 2 

### O emissions from kilns burning natural gas. Addi ng to the confusion, the title of Table AA2 indicates that the emission factors provided are for “fossil fuel-based CH 4 

### and N 2 

### O,” and yet one of the rows of the t able (for which the table gives ellipses in the columns for

CH 4 

### and N 2 

### O) is biogas, which of course is not a fossil fuel, raising the possibility that the ellipses have a different signific ance in that row of the table.

It is therefore unclear whether mills s hould use an emission factor of 0 for CH 4 

### emissions from lime kilns burning residual oil, distillate oil, petroleum coke, and/or biomass, or an emission factor of 0.0027, or should not repor t any number for CH 4 

### emissions from those fuels. It is likewise unc lear what mills should report (or not report)

for N 2 

### O emissions from lime kilns.

The format of Table AA-2 has caused difficulties for pulp mill operators and EPA alike. In at least one instance, EPA post ed incorrect messages concerning lime kiln

CH 4 

### and N 2 

### O emission reporting in a pulp mill’s e GGRT account, later giving different instructions in an e-mail message. AF&PA members have sought cl arification of the implications of Table AA-2 and have been told that the problem is just one of formatting in the eCFR, and that EPA’s intent is clear from the version of Table AA-2 in the proposed regulations published at 75 Fed. Reg. 48,744 (Aug. 11, 2010), on page 48,811. But that version of Table AA-2 was no clearer, showing a 0.0027 in the CH 4 

### column and a 0 in the N 2 

### O for lime kilns burning natural gas, but blanks in both the CH 4 

### column and the N 2 

### O column for all other fossil fuels (and biogas).

10 In contrast, Table AA-1 has blank spaces in the columns for CH 4 and N 2 O emissions from the pulping of all types of fiber besides North American Softwood.

### EPA Air & Radiation Docket (6102T)
Docket ID No. EPA–HQ–OAR–2007–0492 August 31, 2012 Page 14

Obviously, the regulation as published is unclear and is causing confusion among both pulp mill oper ators and regulators. EPA s hould correct Table AA-2 to clearly indicate what default emission factor should be used for each pollutant for each type of fuel, or whether no emission number (not even 0) should be reported.

* * * * * *

For the reasons set forth above, AF&PA and AWC urge you promptly to

reconsider and revise the default emission factors for CH 4 

### and N 2 

### O emissions from burning spent pulping liquor in chemical pulp mill recovery furnaces, in Table AA-1 to 40 C.F.R. Part 98 Subpart AA, and for burning so lid biomass fuels, in Table C-2 to 40 C.F.R. Part 98 Subpart C, as described above . We also request prompt revision of

Table AA-2 to make clear EPA’s intention ab out the default emission factors to be used in estimating CH 4 

### and N 2 

### O emissions from lime k ilns at pulp mills.

If you have any questions about this petit ion for reconsideration/petition for rulemaking, please contact Ms. Nancy Clark , AF&PA’s Director, Climate and Air, at (202) 463-2709 or at N ancy_Clark@afandpa.org.

Sincerely,

Paul Noe Vice President for Public Policy American Forest & Paper Association

Robert W. Glowinski

President and CEO

American Wood Council

cc: Gina McCarthy, Asst. Administ rator, Office of Air and Radiation Sarah Dunham, Dir., Of fice of Atmospheric Programs

### APPENDIX A

# n casi

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT



### METHANE (CH 4 

### ) AND

NITROUS OXIDE (N 2 

### O) EMISSIONS

FROM BIOMASS-FIRED BOILERS

AND RECOVERY FURNACES

TECHNICAL BULLETIN NO. 998

SEPTEMBER 2012

by

J. Derek Sain NCASI Southern Regional Center Newberry, FloridaAcknowledgments

This study was conducted at NCASI’s Southern Regional Center where Ashok Jain is the Regional Manager. The study was coordinated by Derek Sain, Ashok Jain, and Lee Carlson. The report was written by Derek Sain with contributions from Vipin Varma and input from Brad Upton and Reid Miner. Assistance during the field sampling portion was provided by Lee Carlson, Zach Em erson, Ed Hopwood, and Bill Rice. Lab support was provided by Jim Stainfield. Database support was provided by Karen Mentz. This report was edited by Susan Kirkland. NCASI thanks all the companies who participated in the testing program and provided data from their Boiler MACT/CISWI testing for inclusion in this report.

For more information about this research, contact:

J. Derek Sain

Senior Research Associate

NCASI

402 SW 140 th Terrace Newberry, FL 32669
(352) 331-1745, ext. 265 dsain@ncasi.org Dr. Vipin Varma Vice President, Air Quality

NCASI

402 SW 140 th Terrace Newberry, FL 32669
(352) 331-1745, ext. 260 vvarma@ncasi.org

For information about NCASI publications, contact:

Publications Coordinator

NCASI

P.O. Box 13318 Research Triangle Park, NC 27709-3318
(919) 941-6400 publications@ncasi.org

Cite this report as:

National Council for Air and Stream Improvement, Inc. (NCASI). 2012. Methane (CH 4 ) and nitrous oxide (N 2 O) emissions from biomass-fired boilers and recovery furnaces . Technical Bulletin No. 998. Research Triangle Park, N.C.: National Council for Air and Stream Improvement, Inc.

© 2012 by the National Council for Air and Stream Improvement, Inc.National Council for Air and Stream Improvement 

# ncasi

serving the environmental research needs of the forest products industry since 1943



### PRESIDENT’S NOTE

The Mandatory Reporting of Greenhouse Gases Rule (40 CFR Part 98), issued by the United States Environmental Protection Agency in 2009, requir es the annual reporting of greenhouse gas data and other relevant information from large emissions sources. Under this rule, repor ting is required of pulp and paper mills and other facilities with stationa ry combustion units where facility-wide greenhouse gas emissions from applicable sources are greater than 25,000 metric tonnes of carbon dioxide (CO 2 ) equivalents (CO 2 eq.) per year. Wood products facilities are al so required to report if the aggregate maximum rated heat input capacity of stationary fu el combustion units at the facility is 30 MMBtu/hr
or greater and the facility emits 25,000 metric tonnes CO 2 eq. or more per year. While biogenic 

### CO 2 emissions are not considered when determining if a facility’s total emissions exceed the reporting
threshold, emissions of methane ( 

### CH 4 ) and nitrous oxide ( 

### N 2 

### O) from biogenic sources are considered. Emissions from most pulp and paper mills and a limited number of wood products facilities are expected to exceed these reporting thresholds.

As part of this reporting requirement, pulp and paper mills have to report CH 4 and N 2 O emissions from all fuels, both separated by fuel type and in aggregate. This requirement applies to emissions from stationary combustion devices, chemical rec overy furnaces, and lime kilns. Given the limited data availability and uncertainty surrounding current ly available emission factors, NCASI has carried out a study to develop additional data for CH 4 and N 2 O emissions from biomass-fired boilers and kraft recovery furnaces. CH 4 and N 2 O emissions from five combination boilers, five direct contact evaporator (DCE) recovery furnaces, and three non-direct contact evaporator (NDCE) recovery furnaces were measured using Fourier transform in frared spectroscopy (FTIR). Additionally, data

on CH 4 emissions from 22 biomass-fired boilers, obtai ned as part of the 2009 Boiler MACT/CISWI testing program, have been reviewed a nd summarized as part of this study.

The emission factors developed from this study are generally lower than those in current use and are likely more reflective of current emissions from sources in North America.

Ronald A. Yeske

September 2012National Council for Air and Stream Improvement 

# ncasi

serving the environmental research needs of the forest products industry since 1943



### NOTE DU PRÉSIDENT

Le règlement sur la déclaration obligatoire des gaz à effet de serre ( 40 CFR Part 98 ) qui a été publié par l’Agence de protection de l’environnement des États-Unis (EPA) en 2009 oblige les grands

émetteurs à produire une déclaration annuelle sur leur s émissions de gaz à effet de serre et à fournir d’autres renseignements pertinents. En vertu de ce rè glement, les usines de pâtes et papiers et tout autre établissement ayant des unités de combustion stationnaires doivent produire une déclaration si la somme des émissions de gaz à effet de serre de toutes les sources applicables de l’établissement est supérieure à 25 000 tonnes métriques en équivalents CO 2 par année. Les usines de produits du bois doivent aussi produire une déclaration si la somme de la capacité nominale maximale de chaque unité de combustion stationnaire de l’usine est égale ou supérieure à 30 MMBtu/h et si l’usine émet 25 000 tonnes métriques ou plus d’équivalents CO 2 par année. Bien que l’on ne tienne pas compte des
émissions biogéniques de 

### CO 2 pour déterminer si les émissions totales d’un établissement excèdent le seuil de déclaration, il faut cependant tenir compte des émissions de méthane (CH 4 ) et d’oxyde
nitreux (N 2 O) provenant de sources biogéniques. On pré voit que les émissions de la plupart des usines de pâtes et papiers et celles d’un petit nombre d’usines de produits du bois dépasseront les

seuils de déclaration.

En vertu de ce règlement, les usines de pâtes et papiers doivent déclarer les émissions de CH 4 et de

N 2 O de tous les combustibles de deux façons : le total par type de combustible et le total pour

l’ensemble des combustibles combinés. Cette ex igence s’applique aux unités de combustion stationnaires, aux chaudières de récupération des usines de pâte kraft et aux fours à chaux. Compte tenu du peu de données existant dans la littérature et de l’incertitude entourant les facteurs d’émission actuels, NCASI a réalisé une étude pour générer des données supplémentaires sur les émissions de

CH 4 et de N 2 O provenant des chaudières à biomasse et des chaudières de récupération. NCASI a

mesuré les émissions de CH 4 et de N 2 O provenant de cinq chaudières à biomasse, cinq chaudières de récupération avec évaporateurs à contact direct (DCE) et de trois chaudières de récupération avec évaporateurs à contact indirect (NDCE) à l’ai de d’un spectromètre infrarouge à transformée de Fourier (IRTF). De plus, NCASI a analysé les données sur les émissions de CH 4 de 22 chaudières à biomasse obtenues dans le cadre du programme de caractérisation Boiler MACT/CISWI réalisé en 2009, et a inclus un résumé de cette analyse dans la présente étude.

Les facteurs d’émission développés dans le cadre de la présente étude sont généralement inférieurs aux facteurs présentement en usage et sont proba blement plus représentatifs des émissions actuelles des sources d’émission en Amérique du Nord.

Ronald A. Yeske

Septembre 2012National Council for Air and Stream Improvement 

### METHANE (CH 4 

### ) AND NITROUS OXIDE (N 2 

### O) EMISSIONS FROM

BIOMASS-FIRED BOILERS AND RECOVERY FURNACES

TECHNICAL BULLETIN NO. 998

SEPTEMBER 2012

ABSTRACT

NCASI conducted a study to quantify methane (CH 4 ) and nitrous oxide (N 2 O) emissions from biomass-fired boilers and kraft recovery furnaces in order to develop emission factors for potential use in greenhouse gas (GHG) inventories. As part of this study, CH 4 and N 2 O emissions from five biomass-fired boilers, five direct contact evapor ator (DCE) recovery furnaces, and three non-direct contact evaporator (NDCE) recovery furnaces we re measured using extractive Fourier Transform Infrared (FTIR) spectroscopy. Data on CH 4 emissions from 22 biomass-fire d boilers, provided in the 2009 Boiler MACT/CISWI test reports, were also in cluded in this study. For biomass boilers, average

CH 4 and N 2 O emissions were 0.0049 kg/MMBtu and 0.0019 kg/MMBtu, respectively. For DCE recovery furnaces, average CH 4 and N 2 O emissions were 0.0024 kg/MMBtu and 0.00036 kg/MMBtu, respectively. In the case of NDC E recovery furnaces, average CH 4 and N 2 O emissions were 0.0014 kg/MMBtu and 0.00044 kg/MMBtu, respectively. Average emissions of CH 4 and N 2 O were found to be lower than the default emission factors provided by EPA in the Federal Register [74 FR 56260] for use in GHG reporting calculations (solid biomass fuels: 0.032 kg CH 4 /MMBtu and 0.0042 kg

N 2 O/MMBtu in Table C-2; softwood kraft pulping liquor: 0.030 kg CH 4 /MMBtu and 0.005 kg

N 2 O/MMBtu in Table AA-1).

KEYWORDS

biomass boilers, boilers, combination boilers , GHG emission factors, GHGRR, greenhouse gas
(GHG) emissions, methane (CH 4 ), nitrous oxide (N 2 O), recovery furnaces

RELATED NCASI PUBLICATIONS

Technical Bulletin No. 984 (April 2011). Greenhouse gas and non-renewable energy benefits of black liquor recovery.

Special Report No. 08-05 (September 2008). The greenhouse gas and carbon profile of the U.S. forest products sector.

Special Report No. 07-09 (October 2007). The greenhouse gas and carbon profile of the Canadian forest products industry.

Special Report No. 07-02 (February 2007). The greenhouse gas and carbon profile of the global forest products industry.

Special Report No. 01-05 (December 2001). Technologies for reducing carbon dioxide emissions: a resource manual for pulp, paper, and wood products manufactures.

Special Report No. 99-02 (June 1999). Estimating costs for the U.S. forest products industry to meet the greenhouse gas reduction target in the Kyoto protocol.National Council for Air and Stream Improvement 

### ÉMISSIONS DE MÉTHANE (CH 4 

### ) ET D’OXYDE NITREUX (N 2 

### O) PROVENANT DES CHAUDIÈRES À BIOMASSE ET DES CHAUDIÈRES DE RÉCUPÉRATION

BULLETIN TECHNIQUE N O 

### 998

SEPTEMBRE 2012

RÉSUMÉ

NCASI a réalisé une étude pour quantifier les émissions de méthane (CH 4 ) et d’oxyde nitreux (N 2 O) provenant de chaudières à biomasse et de chaudières de récupération (procédé kraft) afin de développer des facteurs d’émission pouvant servir éventuellement à établir des inventaires de gaz à effet de serre
(GES). Dans le cadre de cette étude, NCASI a mesuré les émissions de CH 4 et de N 2 O provenant de cinq chaudières à biomasse, cinq chaudières de récupération avec évaporateurs à contact direct (DCE) et de trois chaudières de récupération avec évaporateurs à contact indirect (NDCE) à l’aide d’un spectromètre infrarouge à transformée de Fourier (IR TF). NCASI a également inclus les données sur les émissions de CH4 provenant de 22 chaudières à biom asse contenues dans les rapports de caractérisation du programme Boiler MACT/CISWI réalisé en 2009. La valeur moyenne des émissions de CH 4 et de

N 2 O des chaudières à biomasse était 0,0049 kg/MMBtu et 0,0019 kg/MMBtu, respectivement. La valeur moyenne des émissions de CH 4 et de N 2 O des chaudières de récupération avec évaporateurs à contact direct (DCE) était 0,0024 kg/MMBtu et 0,00036 kg/MMBtu, respectivement. La valeur moyenne des émissions de CH 4 et de N 2 O des chaudières de récupération avec évaporateurs à contact indirect (NDCE) était 0,0014 kg/MMBtu et 0,00044 kg/ MMBtu, respectivement. On constate que les valeurs moyennes des émissions de CH4 et de N2O s ont inférieures aux valeurs des facteurs d’émission inscrits dans le registre fédéra l [74 FR 56260] par l’EPA pour calculer les émissions de GES à déclarer (biomasse solide : 0,032 kg CH 4 /MMBtu et 0,0042 kg N 2 O/MMBtu dans le tableau C-2; liqueur usée de pâte kraft de résineux : 0,030 kg CH 4 /MMBtu et 0,005 kg N 2 O/MMBtu dans le tableau AA-1).

MOTS-CLÉS

chaudières, chaudières à biomasse, chaudières de récupération, émissions de gaz à effet de serre (GES), exigences de déclaration des GES, facteurs d’émission des GES, méthane (CH 4 ), oxyde
nitreux (N 2 O)

AUTRES PUBLICATIONS DE NCASI

Bulletin technique n o 984 (avril 2011). Greenhouse gas and non-renewable energy benefits of black liquor recovery.

Rapport spécial n o 08-05 (septembre 2008). The greenhouse gas and carbon profile of the U.S. forest products sector.

Rapport spécial n o 07-09 (octobre 2007). The greenhouse gas and carbon profile of the Canadian forest products industry.

Rapport spécial n o 07-02 (février 2007). The greenhouse gas and carbon profile of the global forest products industry.

Rapport spécial n o 01-05(décembre 2001). Technologies for reducing carbon dioxide emissions: a resource manual for pulp, paper, and wood products manufactures.

Rapport spécial n o 99-02 (juin 1999). Estimating costs for the U.S. forest products industry to meet the greenhouse gas reduction target in the Kyoto protocol.National Council for Air and Stream Improvement 

### CONTENTS

1.0 INTRODUCTION ................................................................................................................... 1

1.1 Background .................................................................................................................... 1

1.2 Study Objectives ............................................................................................................ 2

2.0 SAMPLING AND ANALYSIS METHODS ............................................................................ 2

2.1 FTIR .............................................................................................................................. 2

2.2 Boiler MACT/CISWI Testing ......................................................................................... 7

3.0 SOURCE DESCRIPTIONS ..................................................................................................... 7

3.1 NCASI Testing ............................................................................................................... 7

3.2 Boiler MACT/CISWI Testing ....................................................................................... 12

4.0 RESULTS ............................................................................................................................. 12

4.1 NCASI Testing ............................................................................................................. 12

4.2 Boiler MACT/CISWI Testing ....................................................................................... 20

4.3 Category Results .......................................................................................................... 23

5.0 DISCUSSION ....................................................................................................................... 24

5.1 Category Results .......................................................................................................... 24

5.2 Drivers of Methane (CH 4 ) and Nitrous Oxide (N 2 O) Formation and Emissions ............. 25

5.3 Existing Emission Factors ............................................................................................ 26

6.0 CONCLUSIONS ................................................................................................................... 28

REFERENCES ............................................................................................................................... 29

APPENDICES

A Detailed Source Results ............................................................................................... A1

B Principles of FTIR Analysis.......................................................................................... B1

C Method Development ................................................................................................... C1National Council for Air and Stream Improvement 

### TABLES

Table 3.1 NCASI Testing – General Source Descriptions ............................................................. 10

Table 3.2 Boiler MACT/CISWI Testing – General Source Descriptions ....................................... 11

Table 4.1 Recovery Furnace (DCE) ARF3, kg/MMBtu ................................................................ 13

Table 4.2 Bark Boiler ABB2, kg/MMBtu ..................................................................................... 14

Table 4.3 Recovery Furnace (NDCE) BRF5, kg/MMBtu.............................................................. 14

Table 4.4 Combination Boiler CCB4, kg/MMBtu ........................................................................ 15

Table 4.5 Recovery Furnace (NDCE) DRF1, kg/MMBtu ............................................................. 16

Table 4.6 Bark Boiler DBB1, kg/MMBtu ..................................................................................... 16

Table 4.7 Recovery Furnace (NDCE) ERF1, kg/MMBtu .............................................................. 17

Table 4.8 Recovery Furnace (DCE) FRF1, kg/MMBtu ................................................................. 17

Table 4.9 Recovery Furnace (DCE) FRF3, kg/MMBtu ................................................................. 18

Table 4.10 Combination Boiler FBB1, kg/MMBtu ......................................................................... 18

Table 4.11 Recovery Furnace (DCE) GRF1, kg/MMBtu ................................................................ 19

Table 4.12 Recovery Furnace (DCE) GRF2, kg/MMBtu ................................................................ 19

Table 4.13 Combination Boiler GCB3, kg/MMBtu ........................................................................ 20

Table 4.14 Boiler MACT/CISWI Testing – CH 4 Emissions by Source, kg/MMBtu ........................ 21

Table 4.15 Bark/Combination Boiler Category Results, kg/MMBtu ............................................... 22

Table 4.16 Recovery Furnace (NDCE) Category Results, kg/MMBtu ............................................ 23

Table 4.17 Recovery Furnace (DCE) Category Results, kg/MMBtu ............................................... 23

Table 5.1 WRI/WBCSD and IPCC Emission Factors ................................................................... 26

Table 5.2 CH 4 Emissions, kg/MMBtu .......................................................................................... 27

Table 5.3 N 2 O Emissions, kg/MMBtu .......................................................................................... 28



### FIGURES

Figure 2.1 FTIR Sampling System .................................................................................................. 4National Council for Air and Stream Improvement 

### NITROUS OXIDE (N 2 

### O) AND METHANE (CH 4 

### ) EMISSIONS FROM

BIOMASS-FIRED BOILERS AND RECOVERY FURNACES

1.0 INTRODUCTION

1.1 Background

The US Environmental Protection Agency (EPA) issued the Mandatory Reporting of Greenhouse Gases Rule (40 CFR Part 98) in October 2009, requiring the annual reporting of greenhouse gas (GHG) data and other relevant information from large sources and suppliers in the United States (USEPA 2009). Implementation of Part 98 is referred to as the Greenhouse Gas Reporting Rule (GHGRR). Under this rule, reporting is required of pulp and paper mills and other facilities with stationary combustion units where facility-wide greenhouse gas (GHG) emissions from applicable sources are greater than 25,000
metric tonnes of carbon dioxide (CO 2 ) equivalents (CO 2 eq.) per year. This rule is intended to facilitate the development of comprehensive, nationwide emissions data that provide a better understanding of the sources of GHGs and guide the development of policies and programs to reduce emissions. Additionally, the public availability of data is intended to allow reporters to benchmark their emissions against those from similar facilities and aid in identifying cost-effective opportunities to reduce emissions in the future.

CO 2 , methane (CH 4 ), and nitrous oxide (N 2 O) are the three major GHGs produced in pulp and paper manufacturing. Of the three major GHGs, CO 2 emissions are predominant and can be attributed to the burning of fossil fuels and solid biomass fuels (e.g., wood/wood residuals, bark, etc.) in boilers and pulping liquors in chemical recovery furnaces. The pulp and paper industry is heavily reliant on these sources for both energy and chemical recovery. Although biogenic CO 2 emissions do not apply towards the reporting threshold under GHGRR, facilities exceeding the reporting threshold are required to report biogenic CO 2 emissions under a separate category. CH 4 and N 2 O emissions from these sources, both of fossil and of biogenic origin, also need to be reported, both separated by fuel type and in aggregate. CH 4 and N 2 O are emitted in much lower concentrations than CO 2 from combustion sources in the pulp and paper industry. However, given the greater global warming potentials of CH 4 and N 2 O (21 times and 310 times the warming potential of CO 2 , respectively; IPCC 1996) it is important to develop additional data on emissions of these compounds from pulp and paper industry sources.

In the GHGRR, EPA has provided default emission factors for use in estimating CH 4 and N 2 O emissions from the combustion of solid biomass fuels and kraft pulping liquors. The default CH 4 and N 2 O emission factors for solid biomass fuels are 0.032 kg/MMBtu and 0.0042 kg/MMBtu 1 , respectively. For North American softwood kraft pulping liquor, the emission factors are 0.030 kg CH 4 /MMBtu and 0.005 kg

N 2 O/MMBtu (USEPA 2009). The factors for solid biomass combustion were derived by EPA from Tier 1



### CH 4 and 

### N 2 

### O emission factors published by the Intergovernmental Panel on Climate Change (IPCC 2006). The factors for kraft pulping liquor were derived by EPA from an analysis of a summary, prepared by NCASI, of literature generated between 1985 and 2004, and published by The World Research Institute and The World Business Council for Sustainable Development (WRI/WBCSD 2005). EPA chose the highest of the values provided in the summary for use in the GHGRR.

1 Note on emission units: In the GHGRR [74 FR 56260], EPA has mandated the use of specific emission factors for

CH 4 and N 2 O (USEPA 2009). These default emission factors are expressed in kg/MMBtu. Additionally, the rule requires the use of High Heating Values (HHV) of the fuel when using these emission factors to calculate mass emissions of GHG. The emission factors are, in essence, expressed in kg/MMBtu HHV . In order to be consistent with the approach used by EPA in the rulemaking and to better facilitate comparison, all emission data generated from the NCASI study are also expressed in kg/MMBtu , with HHV for the fuel being used as opposed to the Low Heating Value (LHV). It is assumed that there is a 5% difference between the LHV and HHV of the fuels.2 Technical Bulletin No. 998

National Council for Air and Stream Improvement An NCASI review of more recent literature indicates a dearth of accurate and direct emission

measurements of CH 4 and N 2 O from biomass-fired boilers and kraft recovery furnaces, especially those located in North America. As a result, the validity of existing emission factors, including those recommended by EPA, has come under scrutiny. Given the emphasis being placed on GHG inventories, the limited data availability, and uncertainty surrounding currently available emission factors, NCASI carried out a study to develop additional data for CH 4 and N 2 O emissions from these sources.

As part of NCASI testing, emission measurements were conducted at 13 sources, including five biomassfired boilers, five direct contact evaporators (DCE) recovery furnaces, and three non-direct contact evaporator (NDCE) recovery furnaces. CH 4 and N 2 O concentrations in the stack gases were quantified using a portable Fourier transform infrared (FTIR) analyzer.

EPA, using its authority under Section 114 of the Clean Air Act, issued an information collection request (ICR) in June 2009 to approximately 300 industrial, commercial, and institutional boilers and commercial and industrial solid waste incineration (CISWI) sources nationwide, requiring them to conduct emissions testing for several hazardous air pollutants (HAPs) and surrogates like CH 4 . The data collected from this effort have been used in the Boiler MACT rulemaking for floor determinations and setting emission standards. In addition to generating data from targeted testing, NCASI has compiled additional data on

CH 4 emissions from the Boiler MACT/CISWI test reports in order to increase the sample size and develop a more robust emission factor for CH 4 from biomass-fired boilers. CH 4 emission data from 19 boilers tested as part of Boiler MACT program and three boilers tested as part of the commercial and industrial solid waste incineration (CISWI) program have been incorporated into the emission factors developed as part of this study. These boilers were predominantly burning biomass fuels during these tests (>80% of heat input from biomass fuels). CH 4 emissions at these sources were quantified using gas chromatography (GC) as required by EPA Method 18.

1.2 Study Objectives

This study was initiated in response to the need for accurate and direct emission measurements of CH 4 and N 2 O from biomass boilers and recovery furnaces and the lack of availability of such data. Specific objectives of this study were to (1) obtain direct emission measurements of CH 4 and N 2 O from biomassfired boilers, DCE recovery furnaces, and NDCE recovery furnaces via FTIR analysis, (2) summarize

CH 4 emissions data from EPA ’ s recent Boiler MACT ICR, (3) develop CH 4 and N 2 O emission factors for potential use in future PSD and Title V permit modifications, and (4) facilitate a comparison of these factors with the default emission factors mandated by EPA for use in GHG inventories as part of the

GHGRR.

2.0 SAMPLING AND ANALYSIS METHODS

2.1 FTIR

During the NCASI testing, target analytes were quantified on site using a portable FTIR analyzer. In this
instance, EPA Method 320 — Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy (USEPA 1999) — is the most appropriate

method available. ASTM International Standard Test Method D 6348-03 — Determination of Gaseous Compounds by Extractive Direct Interface FTIR Spectroscopy (ASTM 2003) — is an EPA-approved alternative to Method 320. The ASTM method was employed as the primary reference method for all FTIR analyses carried out during this study.

2.1.1 Hardware Components

FTIR Spectrometer : The spectrometer used for analysis was a portable Gasmet TM DX-Series FTIR. The

IR source is a ceramic element heated to 1275 ° C. The interferometer is a Temet Instruments CICCOR

Interferometer with a resolution of 8 cm -1 and an aperture of 1". The sample cell is a 0.5 L multipass cellTechnical Bulletin No. 998 3

National Council for Air and Stream Improvement with gold/rhodium-coated mirrors and a fixed path length of 5 m. The detector is a thermo-electrically

cooled MCT detector.

Data Acquisition System : Laptop with Temet Instruments CALCMET TM software for data acquisition and analysis of IR data. All IR spectra and supporting information were stored on the laptop.

Sample Conditioning System : A sample conditioning system was employed in this study in order to (1) prevent interferences and potential bias due to high levels of source moisture and (2) enhance bag sample stability. The conditioning system was placed in front of the heated-filter assembly and consisted of an empty impinger to condense source moisture and a silica gel impinger to remove entrained moisture and

SO 2 from the gas stream. The performance of the conditioning system was evaluated both in the laboratory and in the field. The results provided in Appendix C indicate that this setup is appropriate for conditioning the gas stream.1

Sample Probe : 3/8" stainless steel 316 tubing of sufficient length to access the sampling location on the

stack.

Heated Filter Assembly : Ceramic filter, rated at 2 m, seated inside heated-filter housing. Dilution/spike gases can be added upstream of the heated filter through a T-valve assembly.

Sampling Lines : Heated 1⁄4" PTFE line. Additional heated 1⁄4" line for dilution/spike gases.

Heated Sample Pump Assembly : The assembly contains a heated KNF pump and a ZrO 2 oxygen sensor. Assembly also includes heater controllers for the sample pump and heated lines, as well as a vacuum gauge for leak checks.

Mass Flow Control : Two Brooks® mass flow controllers capable of supplying an accurate, constant flow of dilution air or spike gas to the heated probe assembly.

Nitrogen Pneumatic Assembly : The assembly allows a single nitrogen source to be split for continuous optical purge and delivery of nitrogen to the heated filter assembly for background measurement.

Gas cylinders : Ultra-high purity nitrogen and EPA protocol calibration standards for analyte spiking and

CTS measurements.

Figure 2.1 depicts the FTIR sampling system configuration.4 Technical Bulletin No. 998

National Council for Air and Stream Improvement Figure 2.1 FTIR Sampling System

2.1.2 Analysis Procedure

The FTIR analysis software requires that, for each source, an appropriate analysis method be set up to deconstruct and analyze the IR spectra. The analysis method can be tailored to the source being tested and defines all elements of the analysis, including the list of compounds being analyzed (analytes), the reference spectra used for calibration, a list of compounds that could be interferences, and specific wavelengths to be evaluated for quantifying the target analytes. This approach serves to minimize interferences and maximize accuracy, given the ability to identify unique interferences for any given source. These analyses methods are provided in Appendix A. A detailed description of FTIR analyzers and the process of FTIR analysis can be found in Appendix B.

2.1.3 Sample Run

The following procedures were followed as part of a complete sample run.

Pre-Run Stack Flow Measurement – Procedure outlined in Section 2.1.6.

Background Spectrum – Ultra-high purity nitrogen was flushed through the system. When the sampling system was completely saturated with nitrogen, a background spectrum was obtained.

Pre-Run CTS Spike – Calibration transfer standard (CTS) spikes were used to ensure the stability of the sampling system. Ethylene from a cylinder of known concentration was flushed through the system. A CTS spectrum was obtained and analyzed. The results from CTS spiking must be within ±5% of the certified cylinder value in order for the testing to proceed.

Sample Source Gas Stream – The source gas stream was sampled from a single point for a period of 30 to

60 minutes.Analyte SpikeCTS Spike Mass Flow

Controller

LaptopUHP Nitrogen Pneumatic Assembly

FTIR

Vent Heated Line

O 2

Heated Sample
Pump Heated Line Conditioning System Heated Filter SS ProbeTechnical Bulletin No. 998 5

National Council for Air and Stream Improvement Analyte Spiking – The analyte spiking procedure described in Section 2.1.5.2 was conducted for N 2 O and

CH 4

.
Post-Run CTS Spike – The CTS spike result must be within ±5% of the certified cylinder value.

Post-Run Stack Flow Measurement – Procedure outlined in Section 2.1.6.

For each sample spectrum, the target analyte concentration and minimum detectable concentration were determined. Concentration data were combined with flow measurements and process data to determine an emission factor corresponding to each run.

To minimize the number of flow measurements taken, one set of stack flow measurements was often used for multiple runs. Run groupings can be found in Appendix A.

2.1.4 Bag Sampling

Direct source measurements using the FTIR sampling setup could not be accomplished in some cases. Where direct sampling was impossible or impractical, the source gas was collected in Tedlar® bags and subsequently analyzed onsite using the FTIR. Sample gas was drawn through the sample conditioning system described in Section 2.1.1, through a sample pump box, and into a 100 L Tedlar® bag. Sample flow was maintained around 3 L/min by employing a critical orifice. Bags were analyzed on site with the FTIR sampling setup. The sample collected in the bag was considered to be a representative composite of the source gas over the sampling period. As discussed earlier, the results from the sample conditioning evaluation provided in Appendix C indicate that the target analytes were stable in the bag for a period of up to four hours.

2.1.5 Quality Assurance/Quality Control

2.1.5.1 Minimum Detectable Concentrations

The minimum detectable concentration (MDC), or detection limit (DL), is the minimum concentration of a compound at which a change can be detected by the instrument with a given statistical probability (typically with a 95% confidence). The MDC for each analyte is a function of two parameters: instrument noise and residual noise in the analysis area. As these two noise parameters increase, the MDC will increase correspondingly. In general, instrument noise remains at a constant level throughout a sampling period. Residual noise, on the other hand, will increase or decrease based on the performance of the analysis algorithm for a particular sample. Residual noise will decrease to zero when all components of the gas stream are identified and accurately quantified. The following calculation is used to determine the MDC for each analyte.

ı ı ı = ı ı ı ı ı ı

ı ı ı ı ı ı ∗ ı ı ı ı

where

REA

rms = root mean square of the residual absorption peaks in the analysis area

REF

rm s = root mean square of the reference absorption peaks in the analysis area, and

C ref = concentration of the analyte reference spectra.

The number of detects obtained during each sample run at a source is also provided in Appendix A as part of the run-by-run results.6 Technical Bulletin No. 998

National Council for Air and Stream Improvement Concentrations below the DL were considered to be non-detects (ND). In the case of sample runs with a mixture of detects and NDs, the concentrations were evaluated using the Kaplan-Meier statistical method (NCASI 2009a, 2009b). The Kaplan-Meier method determines the mean, median, and standard deviation (SD) of a dataset containing both NDs and detects. The Kaplan-Meier mean was calculated and the run was subsequently characterized as a detect. In the case of data sets with all NDs, the average DL was

calculated and the run was labeled as ND.

2.1.5.2 Analyte Spiking

Analyte spiking was used to determine the effectiveness of the FTIR measurement system to quantify the target analytes. From the sample runs, native analyte concentrations were quantified. Total flow was measured at the inlet of the FTIR system to calculate dilution factors (DFs). Dynamic spiking was performed while either sampling directly from the source or from a Tedlar® bag. Certified analyte gas of a known concentration was combined with sample gas upstream of the heated filter at a rate ≤ 10% of the total flow. Spike flow rates were controlled using a mass flow controller. When possible, equivalent spiking concentrations were kept within ±50% of the native source concentration. An expected concentration was calculated based on the following calculation.

ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı ı = ı ı + (ı ı ∗ ı 1 − ı ı ı )

where

CS = (cylinder concentration * DF)

Ua = native source gas concentration.

Percent recovery of the spiked analyte is calculated using the following formula.

% ı ı ı ı ı ı ı ı = ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı

ı ı ı ı ı ı ı ı ı ı ıı ı ı ı ı ı ı ı ı ı ∗ 100%

C oncentration observed corresponds to the quantified concentration of the analyte spike sample. Spike recoveries between 70% and 130% were considered acceptable. Results on CH 4 and N 2 O spike recoveries are also provided in Appendix A. Analyte spiking was used only as a quality check and the percent recoveries calculated from this procedure were not used as scaling factors to adjust the results.

2.1.5.3 Equipment Calibration and Certification

Equipment calibrations and certifications were verified ahead of each sampling trip. Recalibrations were performed, as needed, either by NCASI personnel or by the manufacturer.

2.1.5.4 Gas Cylinder Certification

Ultra-high purity nitrogen was used for background measurements and dilutions. CH 4 and N 2 O cylinders used for spiking were either certified using EPA protocol or a NIST standard and the certified concentration was no more than ±2% of the tag concentration. The ethylene mixture used for CTS spiking was also certified at ±2% of the tag concentration.

2.1.5.5 Reference Spectra

Reference spectra were generated using either certified gas cylinders or from neat compounds. Dilutions were obtained by directly measuring flows using a certified bubble-tube meter. For neat compounds, onlyTechnical Bulletin No. 998 7

National Council for Air and Stream Improvement solutions of known purity were used. Neat solutions were injected using a Cole-Parmer® syringe pump into a heated manifold, vaporized, and subsequently diluted with ultra-high-purity nitrogen to the desired

concentration.

2.1.6 Stack Flow Rate and Process Data

From the list of methods provided in Appendix A of 40 CFR Part 60 (Standards of Performance for New Stationary Sources), Methods 1 through 4 (USEPA 2000, pp. 61779-61832) were used to determine flow rates and moisture content of the source. For stack flow rates, a Type S pitot tube with portable Magnehelic® pressure gauges was used. The pitot was equipped with a K-type thermocouple on the end to measure source temperature at each sample location. A Meriam Instrument digital manometer was used to measure stack and ambient pressure. Oxygen and carbon dioxide concentrations were also measured using the FTIR analyzer. Source moisture was determined using a Rockwell 175-S dry gas meter and an Ohaus® Navigator TM scale for impinger weights. Results of source flow measurements are found in Appendix A.

Data on boiler and furnace operating parameters, fuel firing rates, and fuel heat content were obtained from the facility. In the absence of recent data on fuel heating values, a representative default value provided by the mill was used. The facilities also provided data on firing rates of auxiliary fuels, if any, during sampling. A summary of the process data for each source is provided in Appendix A.

2.2 Boiler MACT/CISWI Testing

CH 4 emissions were measured in the 2009 Boiler MACT/CISWI testing program using EPA Method 18 – Measurement of Gaseous Organic Compound Emissions by Gas Chromatography (USEPA 2000, pp. 62007-62028). It was assumed that all these tests were conducted in accordance with the appropriate equipment, procedure, and QA/QC requirements as outlined in the method. Flow rates were obtaineddirectly from the test reports. The total heat input into the boiler during a test run was determined using Ffactors and concurrent data on fuel firing rates.

3.0 SOURCE DESCRIPTIONS

3.1 NCASI Testing

3.1.1 Mill A

Mill A is a kraft mill located in the southeast United States. It produces approximately 1,200 tons per day (TPD) of bleached softwood dissolving grade/specialty pulp. One recovery furnace and one bark boiler were tested at this facility. The recovery furnace is referred to as source ARF3. The bark boiler is referred

to as source ABB2.

Source ARF3 is a DCE recovery furnace with a permitted capacity of 82,350 pounds of black liquor solids per hour and a steaming capacity of 267,000 pounds per hour (PPH). Particulate is controlled via a dry bottom electrostatic precipitator (ESP). Sampling on source ARF3 was accomplished over a three-day period during which 10 runs were conducted. CH 4 and N 2 O concentrations were determined using FTIR analysis. The boiler produced an average of 217,000 PPH of steam (81% capacity) during these runs. A small amount of No. 6 fuel oil was fired intermittently during the 10 runs, with an average firing rate of 1.9 gallons per minute.

Source ABB2 is a stoker bark boiler with a permitted capacity of 601 MMBtu/hr and a steaming capacity of 400,000 PPH. Particulate is controlled via a venturi scrubber. A portion of the exhaust flow leaving the boiler is diverted to a rotary bark dryer. The two gas streams are recombined before entering the venturi scrubber. Sample ports are located downstream of the scrubber. Sampling on source ABB2 was accomplished over a one-day period during which five runs were conducted. CH 4 and N 2 O concentrations8 Technical Bulletin No. 998

National Council for Air and Stream Improvement were determined using GC and FTIR analyses, respectively. The boiler produced an average of 254,000 PPH of steam (66% capacity) during the runs. The boiler burned 100% bark during the sampling period.

3.1.2 Mill B

Mill B is a kraft mill located in the southeast United States. It produces approximately 2,240 TPD of unbleached softwood linerboard. One NDCE recovery furnace was tested at this facility. The recovery

furnace is referred to as source BRF5.

Source BRF5 has a permitted capacity of 156,780 PPH of black liquor solids and a steaming capacity of 495,700 PPH. Particulate is controlled via a dry bottom ESP. The ESP has two chambers in parallel, with the exhaust gas venting through separate stacks. Concentration measurements were performed on a single stack. Flow data were collected from both stacks. Sampling on source BRF5 was accomplished over a four-day period during which five sample runs were conducted. CH 4 and N 2 O concentrations were determined using FTIR analysis. Five additional runs were conducted as part of the method development study described in Appendix C. The source produced an average of 477,000 PPH of steam (96% capacity) during sampling.

3.1.3 Mill C

Mill C is a hardwood/softwood kraft mill located in the southeast United States. It produces a mixture of bleached tissue and unbleached kraft paper and linerboard with a total capacity of 1,447 TPD. One

combination boiler was tested. The combination boiler is referred to as source CCB4.

Source CCB4 is a stoker boiler burning a combination of bark and No. 6 fuel oil. The boiler has a design capacity of 513 MMBtu/hr and 360,000 PPH of steam. Particulate is controlled via an ESP. Six runs were completed over a two-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. The boiler produced 241,000 PPH of steam (67% capacity) during the sample runs. The average firing rates during the runs were 2,140 PPH of No. 6 fuel oil and 33.65 tons per hour of bark, resulting in 11% and 88% of total heat input, respectively.

3.1.4 Mill D

Mill D is a kraft mill in the southeast United States. It produces approximately 1,560 TPD of bleached softwood dissolving/specialty pulp. One NDCE recovery furnace and one bark boiler were tested at this facility. The recovery furnace is referred to as source DRF1. The bark boiler is referred to as source

DBB1.

Source DRF1 is an NDCE recovery furnace with a rated capacity of 243,750 PPH of black liquor solids and a steaming capacity of 980,000 PPH. Particulate is controlled with a dry bottom ESP. Eight runs were completed over a one-day period with the boiler producing 806,000 PPH (82% capacity) during the sample runs. CH 4 and N 2 O concentrations were determined using FTIR analysis.

Source DBB1 is a stoker boiler designed to burn a combination of bark and natural gas. The boiler is permitted at 642 MMBtu/hr and has a steaming capacity of 540,000 PPH. Particulate is controlled via an ESP. The ESP has two chambers in parallel, with the exhaust gas venting through a common stack. Ten runs were completed over a two-day period with the boiler producing an average of 235,000 PPH (44% capacity). The boiler burned 100% bark during sampling. CH 4 and N 2 O concentrations were determined using FTIR analysis.

3.1.5 Mill E

Mill E is a kraft mill located in the southeast United States capable of producing 860 TPD of bleached softwood pulp. One NDCE recovery furnace was tested at the facility. The recovery furnace is referred to

as source ERF1.Technical Bulletin No. 998 9

National Council for Air and Stream Improvement Source ERF1 is an NDCE recovery furnace with a permitted capacity of 195,800 PPH of black liquor solids and a design steaming capacity of 700,000 PPH. The gas stream is divided into two parallel ESPs and then vented out of separate stacks. Ten runs were completed over a two-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. An average of 171,700 PPH of black liquor solids were fired (88% capacity) during the sample runs.

3.1.6 Mill F

Mill F is a kraft mill located in the southeast United States. It produces approximately 1,180 TPD of unbleached linerboard. Two DCE recovery furnaces and one combination boiler were tested. The two recovery furnaces are referred to as source FRF1 and source FRF3. The combination boiler is referred to

as source FBB1.

Source FRF1 is a DCE recovery furnace with a steaming capacity of 110,000 PPH and a design black liquor firing capacity of 34,400 PPH. Particulate is controlled with a wet ESP. Six runs were carried out over a one-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. During sampling, the boiler produced an average of 85,200 PPH of steam (78% capacity).

Source FRF3 is a DCE recovery furnace with a steaming capacity of 165,000 PPH and a black liquor capacity of 48,300 PPH. Particulate is controlled with a wet bottom ESP. Nine runs were completed over a two-day period with the boiler producing an average of 152,600 PPH of steam (92% capacity). CH 4 and

N 2 O concentrations were determined using FTIR analysis.

Source FBB1 is a combination of a Riley stoker boiler and a CE stoker bark boiler. The two boilers exhaust through a common stack. The Riley boiler has a steaming capacity of 225,000 PPH, while the CE bark boiler has a design steaming capacity of 150,000 PPH, for a combined total capacity of 375,000 PPH. Particulate emissions from both sources are controlled by a common venturi scrubber. Ten runs were completed over a two-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. The boilers produced a total of 310,000 PPH of steam (83% total capacity). During the testing period, both boilers fired 100% wood.

3.1.7 Mill G

Mill G is a kraft mill located in the southeast United States. It produces approximately 900 TPD of bleached hardwood linerboard. Two DCE recovery furnaces and one combination boiler were tested. The two DCE recovery furnaces are referred to as source GRF1 and source GRF2. The combination boiler is

referred to as source GCB3.

Source GRF1 is a DCE recovery furnace with a design capacity of 124,000 PPH of black liquor and a steaming capacity of 398,000 PPH of steam. Emissions are divided into two parallel dry bottom ESPs and then vented through separate stacks. Concentration measurements were performed on a single stack. Flow data were collected from both stacks. Six runs were conducted at the source over a one-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. During sampling an average of 120,400 PPH of black liquor solids were fired (97% capacity).

Source GRF2 is a DCE recovery furnace with a design capacity of 124,000 PPH of black liquor and a steaming capacity of 398,000 PPH of steam. Emissions are divided into two parallel wet bottom ESPs and then vented through separate stacks. Concentration measurements were performed on a single stack. Flow data were collected from both stacks. Six runs were conducted over a one-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. An average of 104,900 PPH of black liquor solids were fired (85% capacity) during testing.Table 3.1 NCASI Testing – General Source Descriptions

Data Source Mill ID Source ID Type Primary Fuel Secondary Fuel Capacity Capacity Units

NCASI Testing A ARF3 DCE Recovery Black Liquor No. 6 F uel O il 267,000 lb/hr steam

NCASI Testing A ABB2 Stoker Bark 601 MMBtu/hr

NCASI Testi ng B BRF5 NDCE Recovery Black Liquor 495,700 lb/hr steam

NCASI Testing C CCB4 Stoker Bark No. 6 F uel O il 513 MMBtu/hr

NCASI Testing D DRF1 NDCE Recovery Black Liquor 980,000 lb/hr steam

NCASI Testing D DBB1 Stoker Bark 642 MMBtu/hr

NCASI Testing E E RF1 NDCE Recovery Black Liquor 700,000 lb/hr steam

NCASI Testing F FRF1 DCE Recovery Black Liquor 110,000 lb/hr steam

NCASI Testing F FRF3 DCE Recovery Black Liquor 165,000 lb/hr steam

NCASI Testing F FBB1 Combo. Stoker Wood 375,000 lb/hr steam

NCA SI Testing G GRF1 DCE Recovery Black Liquor 398,000 lb/hr steam

NCASI Testing G GRF2 DCE Recovery Black Liquor 398,000 lb/hr steam

NCASI Testing G GCB3 Stoker Bark No. 6 F uel O il 499 MMBtu/hrTable 3.2 Boiler MACT/CISWI Testing – General Source Descriptions

Data Source Mill ID Source ID Type Primary Fuel Secondary Fuel Capacity Capacity Units

MACT H HCB1 Stoker Bark Resin ated Wood, Natural Gas 470 MMBtu/hr

MACT I ICB1 Fluidized Bed Bark Municipal Solid Waste, Natural Gas 125,000 lb/hr steam

MACT J JCB2 Stoker Bark TDF, N o. 6 F uel O il 500 MMBtu/hr

MACT K KCB2 Fuel Cell Bark 100 MMBtu/hr

MACT L LCB1 Fuel Cell Wood/Bark 115 MMBtu/hr

MACT M MCB3 Fuel Cell Wood/Bark 29,580 lb/hr steam

MACT N NCB1 Stoker Bark 435 MMBtu /hr

MACT O OCB4 Stoker Bark No. 6 fuel oil , Natural Gas 800 MMBtu/hr

MACT P PCB4 Fluidized Bed Bark WWT Sludge, TDF 877 MMBtu/hr

MACT Q QCB8 Stoker WWT Sludge Wood/Bark 236 MMBtu/hr

MACT R RCB1 Fuel Cell Bark

MACT S SCB1 Stoker Bark Cross ties, Nat ural Gas, WWT Sludge 454 MMBtu/hr

MACT T TCB1 Fuel Cell Wood 249 MMBtu/hr

CISWI U UCB2 Stoker Wood/Bark OCC rejects, WWT Sludge, Natural Gas 940 MMBtu/hr

CISWI V VCB2 Stoker Bark WWT Sludge, Cross ties, Natural Gas 667 MMBtu/hr

CISWI W WCB1 Stoker Bar k Natural Gas, WWT Sludge, OCC rejects 900 MMBtu/hr

MACT X XCB1 Stoker Bark 200,000 lb/hr steam

MACT Y YCB1 Stoker Bark Natural Gas 337 MMBtu/hr

MACT Z ZCB1 Bark 30 MMBtu/hr

MACT AA AACB1 Fuel Cell Wood/Bark 28 MMBtu/hr

MACT AB ABCB1 Dutch oven Wo od/ Bark 90,000 lb/hr steam

MACT AC ACCB1 Fluidized Bed Bark 856 MMBtu/hr12 Technical Bulletin No. 998

National Council for Air and Stream Improvement Source GCB3 is a stoker boiler burning a combination of wood and No. 6 fuel oil. The boiler has a design capacity of 499 MMBtu/hr and 300,000 PPH of steam. Particulate is controlled with a venturi scrubber. Six runs were completed over a one-day period. CH 4 and N 2 O concentrations were determined using FTIR analysis. The boiler produced an average of 183,600 PPH of steam (61% capacity). During the testing period, the source fired 244.6 MMBtu/hr of bark and 4.3 MMBtu/hr of No. 6 fuel oil, resulting in 98% and 2% of the total Btu input, respectively.

3.2 Boiler MACT/CISWI Testing

Test data from 22 biomass-fired boilers were extracted from EPA ’ s 2009 Boiler MACT and CISWI databases (19 boilers and 3 incinerators). Boilers were selected if CH 4 testing was conducted with > 80% of the heat input on average coming from biomass fuels. With the exception of one source, OCB4, where only two tests were conducted with the boiler burning predominantly biomass, all other sources had three
test runs. In all cases, CH 4 concentrations were determined using EPA Method 18. Table 3.2 provides a general description of each source selected from the database, along with information on the types of fuels being burned during testing. Appendix A contains the percentages of each fuel burned during

individual runs.

4.0 RESULTS

In the final GHG reporting rule [74 FR 56260], EPA has mandated the use of specific emission factors for

CH 4 and N 2 O (USEPA 2009). These emission factors are expressed in units of kg/MMBtu. Additionally, the rule requires use of high heating value (HHV) of the fuel when utilizing these emission factors to calculate mass emissions of GHG (in kg). These emission factors are, in effect, expressed in kg/MMBtu

HHV . In order to be consistent with the approach used by EPA in the rulemaking and to better facilitate comparison, all emission data in this report are also expressed in kg/MMBtu, with HHV for the fuel being used as opposed to the low heating value (LHV) in calculations. It has been assumed that there is a 5%

difference between the LHV and HHV of fuels.

4.1 NCASI Testing

All reported emissions have been calculated from measured in-stack concentrations, expressed on a dry basis. Emissions are reported in kg/MMBtu to be consistent with the approach used by EPA in the GHGRR. Emissions are calculated and reported using the high-heating value (HHV) of the fuel as the basis. Detailed results for each source are listed in Appendix A.

In the case of combination boilers burning a mixture of biomass and other fuels, emissions are expressed based on the combined fuel energy input. CH 4 and N 2 O emissions are expected to be dictated more by combustion conditions than fuel properties (WRI/WBCSD 2005; Bonn, Pelz, and Baumann 1995). Even though multiple fuels were being burned during some of these tests, biomass fuels were the predominant fuel and accounted for ~ 90% of heat input in all cases. Subsequently, it is reasonable to compare these emission factors against the default factors for solid biomass fuels in the GHG reporting rule.

4.1.1 Treatment of Non-detect (ND) Data

When utilizing the direct sampling and analysis methodologies with the FTIR, as outlined above in Section 2.1, each sample run involves the recording and analysis of multiple IR spectra. In effect, each reported data point (labeled as a Run in Tables 4.1 through 4.14) reflects an average of multiple measurements. For each IR spectrum analyzed, the target analyte concentration and DL were calculated. Detection limits were determined as outlined in Section 2.1.5.1. All analytical results were used to
determine the minimum, maximum, mean, standard deviation (SD), and median concentrations for CH 4 and N 2 O for the sample run. Non-detect (ND) data was treated as follows:Technical Bulletin No. 998 13

National Council for Air and Stream Improvement · When a sample run dataset included a mixture of detects and NDs, the concentrations were evaluated using the Kaplan-Meier statistical method (NCASI 2009a, 2009b). The Kaplan-Meier

statistical mean concentration for the run was calculated and the run was characterized as a detect.

· In the case of sample runs with all NDs, the mean DL was calculated and the run was marked as

ND.

· In the case of sample runs with only one detect, the ND values are reduced to 1⁄2 the DL, the resulting mean concentration was calculated, and the run was characterized as a detect.

· ND data from multiple sample runs at a given source were also treated as described above.

Spike recoveries were calculated for each run as described in Section 2.1.5.2. In the case of data sets with a mixture of detects and NDs, spike recovery was calculated by using the Kaplan-Meier statistical mean as the native source gas concentration. For runs with all NDs, no spike recovery was calculated. Spike recoveries between 70% and 130% were considered acceptable. Runs with spike recoveries outside this range were removed.

4.1.2 Mill A

4.1.2.1 Recovery Furnace (DCE) ARF3

Ten sample runs were completed at source ARF3. One of the 10 sample runs yielded a ND for CH 4 . N 2 O concentrations were above the DL for all sample runs. Run 4 did not meet the QA requirements in terms of spike recovery for N 2 O. Subsequently, this data point was excluded from summary calculations. The average spike recoveries for the reported CH 4 and N 2 O concentrations were 91.1% and 86.8%, respectively. Table 4.1 summarizes the CH 4 and N 2 O emissions for source ARF3.

Table 4.1 Recovery Furnace (DCE) ARF3, kg/MMBtu

Run CH 4 N 2 O

1 0.00015 0.00043

2 0.00068 0.00032

3 0.00010 0.00028

4 0.00014

5 0.0 0019 0.00035

6 0.00016 0.00027

7 0.00012 0.00024

8 0.00008 0.00013

9 ND[ 0.00013] 0.00027

10 0.00027 0.00015
Range 0.00008

– 0.00068 0.00013

– 0.00043

Mean 0.00020 0.00027

St. Dev 0.00017 0.00009

Median 0.00014 0.00027

4.1.2.2 Bark Boiler ABB2

Five sample runs were completed at source ABB2. However, sample interferences prevented the accurate quantification of CH 4 using the FTIR. Subsequently, the bag samples were analyzed for CH 4 using a14 Technical Bulletin No. 998

National Council for Air and Stream Improvement GC/FID (equivalent to using EPA Method 18). Four of the five sample runs were analyzed. The Tedlar bag corresponding to Run 4 did not contain adequate amounts of sample gas to carry out a GC analysis. No spiking was conducted for CH 4 . All sample runs were above the DL for N 2 O concentrations. The average spike recovery for N 2 O was 91.7%. Table 4.2 summarizes the CH 4 and N 2 O emissions for source

ABB2.

Table 4.2 Bark Boiler ABB2, kg/MMBtu

Run CH 4 N 2 O

1 0.00044 0.0018

2 0.00083 0.0014

3 0.0015 0.0023

4 0.0040

5 0.0016 0.0038
Range 0.00044

– 0.001 6 0.0014

– 0.0040

Mean 0.0011 0.0027

St. Dev 0.0006 0.0012

Median 0.0012 0.0023

4.1.3 Mill B

4.1.3.1 Recovery Furnace (NDCE) BRF5

Five sample runs were completed at source BRF5. One of these runs yielded a ND for CH 4 . Additionally,

Run 2 and Run 3 CH 4 spike recovery results did not meet QA requirements. These data points were removed from summary calculations. All sample runs were above the DL for N 2 O concentrations. The average spike recoveries for the reported CH 4 and N 2 O concentrations were 81.2% and 113.1%, respectively. Table 4.3 summarizes the CH 4 and N 2 O emissions for source BRF5.

Table 4.3 Recovery Furnace (NDCE) BRF5, kg/MMBtu

Run CH 4 N 2 O

1 0.00090 0.00062

2 0.00065

3 0.00086

4 ND[0.00039] 0.0011

5 0.0010 0.00088
Range ND [<0.00039]

– 0.0010 0.00062

– 0.0011

Mean 0.00093 0.00082

St. Dev 0.00007 0.00020

Median 0.00039 0.00086Technical Bulletin No. 998 15

National Council for Air and Stream Improvement 4.1.4 Mill C

4.1.4.1 Combination Boiler CCB4

Six sample runs were completed at source CCB4. All sample runs were above the DL for CH 4 and N 2 O concentrations. The average spike recovery for CH 4 and N 2 O was 99.3% and 98.9%, respectively. Table

4.4 summarizes the CH 4 and N 2 O emissions for source CCB4.

Table 4.4 Combination Boiler CCB4, kg/MMBtu

Run CH 4 N 2 O

1 0.00076 0.0014

2 0.00040 0 .0012

3 0.0048 0.0014

4 0.0046 0.0016

5 0.0077 0.0019

6 0.00042 0.0014
Range 0.00040

– 0.0077 0.0012

– 0.0019

Mean 0.0031 0.0015

St. Dev 0.0030 0.0002

Median 0.0027 0.0014

4.1.5 Mill D

4.1.5.1 Recovery Furnace (NDCE) DRF1

Eight sample runs were completed at source DRF1. Seven of the eight runs yielded NDs for CH 4 . As outlined in the approach laid out in Section 4.1.1, since seven of the eight runs were NDs, the ND values were reduced to 1⁄2 DL and characterized as detects for summary calculations. The spike recovery for the lone detect was 93.0%. Four of the eight runs were ND for N 2 O. Run 1 for N 2 O was ND at a detection level that was greater than the highest detected concentration for the set of runs. Since the Kaplan-Meier method states that there is no useful information in such a value, this data point was removed from the data set (NCASI 2009a). The average spike recovery for N 2 O was 80.9%. Table 4.5 summarizes CH 4 and

N 2 O emissions for DRF1.16 Technical Bulletin No. 998

National Council for Air and Stream Improvement Table 4.5 Recovery Furnace (NDCE) DRF1, kg/MMBtu

Run CH 4 N 2 O

1 0.000042

2 0.000047 0.00012

3 0.000041 ND[0.00018]

4 0.000046 ND[0.00016]

5 0.000034 0.00018

6 0.000047 0.00018

7 0.000037 ND[0.00014]

8 0.000038 0.00017
Range 0.000034

– 0.000047 0.00012

– 0.00018

Mean 0.000042 0.0001 5

St. Dev 0.00003

Median 0.00014

NOTE: Shaded values are 1⁄2 DL

.

4.1.5.2 Bark Boiler DBB1

Ten runs were completed at source DBB1. All 10 runs were above the DL for CH 4 concentrations. The average spike recovery was 95.6%. Two of the 10 runs were ND for N 2 O concentrations. The average spike recovery was 90.4%. Table 4.6 summarizes CH 4 and N 2 O emissions for DBB1.

Table 4.6 Bark Boiler DBB1, kg/MMBtu

Run CH 4 N 2 O

1 0.00022 0.00091

2 0.00047 0.0013

3 0.00017 0.0011

4 0.00020 0.00090

5 0.00022 0 .0012

6 0.00046 0.0012

7 0.00025 ND[0.00062]

8 0.00030 0.0013

9 0.00023 0.0010

10 0.00024 ND[0.00070]
Range 0.00017

– 0.00047 ND[0.00062]

– 0.0013

Mean 0.00028 0.0011

St. Dev 0.00011 0.0002

Median 0.00023 0.0010

4.1.6 Mill E

4.1.6.1 Recovery Furnace (NDCE) ERF1

Ten runs were completed at source ERF1. All 10 runs were above the DL for CH 4 concentrations. The average spike recovery was 98.7%. Seven of the 10 runs were ND for N 2 O concentrations. The average spike recovery was 99.9%. Table 4.7 summarizes CH 4 and N 2 O emissions for ERF1.Technical Bulletin No. 998 17

National Council for Air and Stream Improvement Table 4.7 Recovery Furnace (NDCE) ERF1, kg/MMBtu

Run CH 4 N 2 O

1 0.000065 ND[0.000099]

2 0.0013 ND[0.00019 ]

3 0.0056 ND[0.00051 ]

4 0.0029 ND[0.00030 ]

5 0.00087 ND[0.00016 ]

6 0.0051 ND[0.00051 ]

7 0.0033 0.000 65

8 0.0041 ND[0.00044]

9 0.0023 0.00065

10 0.0057 0.00027
Range 0.000065

– 0.0057 ND[0.000099]

– 0.00065

Mean 0.0031 0.00034

St. Dev 0.0020 0.00015

Median 0.0031 0.00016

4.1.7 Mill F

4.1.7.1 Recovery Furnace (DCE) FRF1

Six runs were completed at source FRF1. All CH 4 and N 2 O concentrations were above the DLs. The average spike recoveries for CH 4 and N 2 O were 99.0% and 101.9%, respectively. Table 4.8 summarizes

CH 4 and N 2 O emissions for FRF1.

Table 4.8 Recovery Furnace (DCE) FRF1, kg/MMBtu

Run CH 4 N 2 O

1 0.014 0.00072

2 0.016 0.00085

3 0.0098 0.00044

4 0.0061 0.00054

5 0.0020 0.00069

6 0.015 0.00069
Range 0.0020

– 0.016 0.00044

– 0.00085

Mean 0.010 0.00065

St. Dev 0.005 0.00015

Median 0.012 0.00069

4.1.7.2 Recovery Furnace (DCE) FRF3

Nine runs were completed at source FRF1. All CH 4 and N 2 O concentrations were above the DLs. The average spike recoveries for CH 4 and N 2 O were 98.2% and 92.8%, respectively. Table 4.9 summarizes

CH 4 and N 2 O emissions for FRF3.18 Technical Bulletin No. 998

National Council for Air and Stream Improvement Table 4.9 Recovery Furnace (DCE) FRF3, kg/MMBtu

Run CH 4 N 2 O

1 0.00077 0.00045

2 0.00057 0.00044

3 0.0011 0.00049

4 0.0016 0.00049

5 0.0015 0.00042

6 0.0015 0.00060

7 0.00041 0.00039

8 0.00026 0.00034

9 0.0021 0.00076
Range 0.00026

– 0.0021 0.00034

– 0.00076

Mea n 0.0011 0.00049

St. Dev 0.00063 0.00012

Median 0.0011 0.00045

4.1.7.3 Combination Boiler FBB1

Ten runs were completed at source FBB1. All CH 4 concentrations were above the DL. The average spike recovery was 100.2%. Two of the 10 runs were ND for N 2 O concentrations. The average spike recovery

was 101.4%. Table 4.10 summarizes CH 4 and N 2 O emissions for FBB1.

Table 4.10 Combination Boiler FBB1, kg/MMBtu

Run CH 4 N 2 O

1 0.054 0.00054

2 0.078 0.00067

3 0.024 0.00028

4 0.058 ND[0.00041]

5 0.01 7 0.0014

6 0.017 0.0023

7 0.057 ND[0.00043]

8 0.028 0.00069

9 0.054 0.00030

10 0.027 0.00066
Range 0.017

– 0.078 0.00028

– 0.0023

Mean 0.041 0.00073

St. Dev 0.021 0.00060

Median 0.041 0.00054

4.1.8 Mill G

4.1.8.1 Recovery Furnace (DCE) GRF1

Six runs were completed at source GRF1. Five of the six runs were below the DL for CH 4 . The ND values were reduced to 1⁄2 DL and marked as detect for calculations. The spike recovery for the detect run wasTechnical Bulletin No. 998 19

National Council for Air and Stream Improvement 99.1%. All N 2 O concentrations were above the DL. The average spike recovery was 98.7%. Table 4.11

summarizes CH 4 and N 2 O emissions for GRF1.

Table 4.11 Recovery Furnace (DCE) GRF1, kg/MMBtu

Run CH 4 N 2 O

1 0.00011 0.00012

2 0.00010 0.00019

3 0.00011 0.00031

4 0.00015 0.00026

5 0.00011 0.00018

6 0.00 010 0.00014
Range 0.00010

– 0.00015 0.00012

– 0.00031

Mean 0.00011 0.00020

St. Dev 0.00007

Median 0.00018

NOTE: Shaded values are 1⁄2 DL

.

4.1.8.2 Recovery Furnace (DCE) GRF2

Six runs were completed at source GRF2. Run 2 was ND for CH 4 and the DL was greater than the highest detected concentration. The ND value was removed before statistical calculations. The average spike recovery was 94.7%. All N 2 O concentrations were above the DL. The average spike recovery was 97.0%.

Table 4.12 summarizes CH 4 and N 2 O emissions for GRF2.

Table 4.12 Recovery Furnace (DCE) GRF2, kg/MMBtu

Run CH 4 N 2 O

1 0.00016 0.00026

2 0.00033

3 0.00013 0.000092

4 0.00010 0.00012

5 0.00011 0.00017

6 0.00013 0.00018
Range 0.00010

– 0.00016 0.000092

– 0.00033

Mean 0.0001 3 0.00019

St. Dev 0.00002 0.00009

Median 0.00013 0.00017

4.1.8.3 Combination Boiler GCB3

Six runs were completed at source GCB3. All CH 4 and N 2 O concentrations were above the DLs. The average spike recoveries for CH 4 and N 2 O were 100.9% and 103.6%, respectively. Table 4.13

summarizes CH 4 and N 2 O emissions for GCB3.20 Technical Bulletin No. 998

National Council for Air and Stream Improvement Table 4.13 Combination Boiler GCB3, kg/MMBtu

Run CH 4 N 2 O

1 0.00099 0.0020

2 0.00065 0.0024

3 0.00075 0.0036

4 0.00056 0.0037

5 0.00062 0.0048

6 0.00054 0.0038
Range 0.00054

– 0.00099 0.0020

– 0.0048

Mean 0.00068 0.0034

St. Dev 0.00017 0.0010

Median 0.00064 0.0036

4.2 Boiler MACT/CISWI Testing

For sources tested as part of Boiler MACT/CISWI testing, individual test results (labeled as Runs) were also subjected to the statistical treatment outlined in Section 4.1.1.

The source emissions for CH 4 reported in Table 4.14 have been calculated from the measured, in-stack concentrations expressed on a dry basis. All emissions have been calculated using the combined energy inputs from the fuel, on a high-heating value (HHV) basis. Detailed results for each source are provided in Appendix A.Table 4.14 Boiler MACT/CISWI Testing – CH 4 Emissions by Source, kg/MMBtu

Source Run 1 Run 2 Run 3 Range Mean St. Dev

. Median

HCB1 ND[0.00012 ] ND[0.00011 ] ND[0.00011 ] ND[0.00011]

– ND[0.00012 ] ND[0.00012 ]

ICB1 0.0018 0.0016 0.0020 0.0016

– 0.0020 0.0018 0.0002 0.0018

JCB2 0.0087 0.0037 0.010 0.0037

– 0.010 0.0076 0.0035 0.0087

KCB2 0.00061 0.00029 0.00037 0.00029

– 0.00061 0.00043 0.00017 0.00037

LCB1 0.00092 0.00037 0.00086 0.00037

– 0.00092 0.00072 0.00030 0.00086

MCB3 0.00022 0.00025 0.00048 0.00022

– 0.00048 0.00032 0.00014 0.00025

NCB1 0.0014 0.0011 0.00050 0.00050

– 0.0014 0.0010 0.0005 0.0011

OCB4 0.00015 0.0003 1 0.00015

– 0.00031 0.00023 0.00011 0.00023

PCB4 0.00017 0.00016 0.00021 0.00016

– 0.00021 0.00018 0.00003 0.00017 QCB8 0.00076 0.00069 0.00064 0.00064

– 0.00076 0.00070 0.00006 0.00069

RCB1 0.0036 0.00067 0.00046 0.00046

– 0.0036 0.0016 0.0017 0.00067

SCB1 0.0012 0.0047 0.00078 0.00078

– 0.0047 0.0022 0.0022 0.0012

TCB1 0.00053 0.0017 0.0024 0.00053

– 0.0024 0.0015 0.00094 0.0017

UCB2 0.0050 0.0023 0.00075 0.00075

– 0.0050 0.0027 0.0022 0.0023

VCB2 0.00055 0.00075 0.0023 0.00055

– 0.0023 0.0012 0.00 095 0.00075

WCB1 0.0013 0.0014 0.00093 0.00093

– 0.0014 0.0012 0.00023 0.0013

XCB1 0.0056 0.0038 0.0030 0.0030

– 0.0056 0.0041 0.0013 0.0038

YCB1 0.048 0.056 0.032 0.032

– 0.056 0.046 0.012 0.048

ZCB1 0.0046 0.0042 0.0034 0.0034

– 0.0046 0.0041 0.0006 0.0042

AACB1 0.0030 0.011 0.00091 0.00091

– 0.011 0.0048 0.0051 0.0030

ABCB1 0.00084 0.00063 0.00063 0.00063

– 0.00084 0.00070 0.00012 0.00063

ACCB1 0.00096 0.00014 0.00043 0.00014

– 0.00096 0.00051 0.00041 0.0004322 Technical Bulletin No. 998

National Council for Air and Stream Improvement 4.3 Category Results

4.3.1 Biomass-Fired Boilers

Five biomass-fired boilers were tested using FTIR. The mean CH 4 emission from these sources was 0.0093 kg/MMBtu. Data on CH 4 emissions from 22 biomass-fired boilers were extracted from available Boiler MACT/CISWI reports. The mean CH 4 emission from these sources was 0.0039 kg/MMBtu. Combining the two data sets then results in a mean CH 4 emission of 0.0049 kg/MMBtu.

The mean N 2 O emission was 0.0019 kg/MMBtu. Table 4.15 summarizes the CH 4 and N 2 O emissions

from bark/combination boilers.

Table 4.15 Bark/Combination Boiler Category Results, kg/MMBtu

Data Source Source ID CH 4 N 2 O

NCASI Testing ABB2 0.0011 0.0027
NCASI Testing CCB4 0.0031 0.0015
NCASI Testing DBB1 0.00028 0.0011
NCASI Testing FBB1 0.041 0.00073 NCASI Testing GCB3 0.00068 0.0034

MACT HCB1 ND[0.00012]

MACT ICB1 0.0018

MACT JCB2 0.0076

MACT KCB2 0.00043

MACT LCB1 0.00072

MACT MCB3 0.00032

MACT NCB1 0.0010

MACT OCB4 0.00023

MACT PCB4 0.00018

MACT QCB8 0.00070

MACT RCB1 0.0016

MACT SCB1 0.0022

MACT TCB1 0.0015

CISWI UCB2 0.0027

CISWI VCB2 0.0012

CISWI WCB1 0.0012

MACT XCB1 0.0052

MACT YCB1 0.046

MACT ZCB1 0.0048

MACT AACB1 0.0048

MACT ABCB1 0.00070

MACT ACCB1 0.00051

Range ND[0.00012]

– 0.046 0.00073

– 0.0034

Mean 0.0049 0.0019

St. Dev 0.011 0.0011

Median 0.0012 0.0015Technical Bulletin No. 998 23

National Council for Air and Stream Improvement 4.3.2 NDCE Recovery Furnaces

Three NDCE recovery furnaces were tested. The mean CH 4 emission was 0.0014 kg/MMBtu. The

mean N 2 O emission was 0.00044 kg/MMBtu. Table 4.16 summarizes the CH 4 and N 2 O emissions from NDCE recovery furnaces.

Table 4.16 Recovery Furnace (NDCE) Category Results, kg/MMBtu

Data Source Source ID CH 4 N 2 O

NCASI Testing BRF5 0.00093 0.00082 NCASI Testing DRF1 0.000042 0.00015 NCASI Testing ERF1 0.0031 0.000 34
Range 0.000042

– 0.0031 0.00015

– 0.00082

Mean 0.0014 0.00044

St. Dev 0.0016 0.00035

Median 0.00093 0.00034

4.3.3 DCE Recovery Furnaces)

Five DCE recovery furnaces were tested. The mean CH 4 emission was 0.0024 kg/MMBtu. The mean

N 2 O emission was 0.00036 kg/MMBtu. Table 4.17 summarizes the CH 4 and N 2 O emissions from DCE recovery furnaces.

Table 4.17 Recovery Furnace (DCE) Category Results, kg/MMBtu

Data Source Source ID CH 4 N 2 O

NCASI Testing ARF3 0.00020 0.00027 NCASI Testing FRF1 0.010 0.00065 NCASI Testing FRF3 0.0011 0.00049 NCASI Testing GRF1 0.00011 0.00020 NCASI Testing GRF2 0.00013 0.00019
Range 0.00011

– 0.010 0.00019

– 0.00065

Mean 0.0024 0.00036

St. Dev 0.0045 0.00020

Median 0.00020 0.0002724 Technical Bulletin No. 998

National Council for Air and Stream Improvement 5.0 DISCUSSION

5.1 Category Results

5.1.1 Biomass-Fired Boilers

Five biomass-fired boilers were tested using the FTIR as part of NCASI testing and data from 22 biomass-fired boilers were obtained from the Boiler MACT/CISWI reports. On average, CH 4 emissions from boilers were higher than those observed in DCE and NDCE recovery furnaces , and amounted to 0.0049 kg/MMBtu (with median emissions of 0.0012 kg/MMBtu). N 2 O emissions from biomass boilers were higher than those observed in NDCE and DCE recovery furnaces. The mean

and median N 2 O emission rate from biomass-fired boilers was 0.0019 kg/MMBtu and 0.0015 kg/MMBtu, respectively.

As indicated in Table 4.15, CH 4 emissions from two out of the 27 boilers included in this study, viz., FBB1 and YCB1, were significantly higher than emissions from other boilers included in this study. Specifically, CH 4 emissions from these two sources were approximately five times greater than the next smallest value measured, and contributed to the higher mean value for CH 4 emissions as compared to the median. While typical boiler operating parameters at these two sources were within normal operating ranges, the carbon monoxide (CO) concentrations measured during these tests were significantly higher than those observed on the other sources. It is well documented that CO is a surrogate for incomplete combustion in boilers. The prevailing higher CO concentrations could therefore explain the higher CH 4 emission rates measured from these two sources. It is possible that the test runs encompassed periods of transient changes in fuel quality or boiler operation that affected the overall quality of combustion. While a more detailed examination of the correlation between CO

and CH 4 emissions from the sources tested during this study is beyond the scope of this report, it is worthwhile to note this observed discrepancy in measured CO concentrations.

5.1.2 NDCE Recovery Furnaces

A total of three NDCE recovery furnaces were tested as part of this study. CH 4 emissions from this source category were low and quite variable. The mean and median CH 4 emission rate was 0.0014 kg/MMBtu and 0.00093 kg/MMBtu, respectively. Mean and median N 2 O emissions were 0.00044 kg/MMBtu and 0.00034 kg/MMBtu, respectively.

Source ERF1 contained the highest and most variable CH 4 emissions, ranging from 0.000065 to 0.0057 kg/MMBtu. CH 4 results for source BRF5 were calculated using three of the five runs, as the remaining two runs provided unacceptable analyte spiking results. For this source, dynamic spiking was carried out while sampling directly from the stack. Given the observed variability in CH 4 concentrations at this source and the potential for concentrations to change between the spiking run and the sample run, it is not surprising that spike recoveries for 2 of the runs were outside the acceptable range of 70% to 130%.

5.1.3 DCE Recovery Furnaces

The mean and median CH 4 emission rate was 0.0024 kg/MMBtu and 0.00020 kg/MMBtu, respectively in the five DCE furnaces tested during this study. N 2 O emissions from DCE recovery furnaces were the lowest of the three categories, with mean and median emissions rate of 0.00036 kg/MMBtu and 0.00027 kb/MMBtu, respectively.

CH 4 emissions from source FRF1 were significantly higher than emissions from the other four DCE furnaces tested during this study. One of the sample runs at source ARF3 did not meet the QA spiking requirements for N 2 O and was subsequently removed from the dataset. The cause of the low spike recovery could not be determined.Technical Bulletin No. 998 25

National Council for Air and Stream Improvement 5.2 Drivers of Methane (CH 4 ) and Nitrous Oxide (N 2 O) Formation and Emissions

The variability observed in CH 4 and N 2 O emissions can be attributed to a number of factors. In the

case of CH 4 , combustion conditions inside the boiler are expected to be the dominant contributing

factor. N 2 O emissions, on the other hand, can be influenced both by combustion conditions and fuel nitrogen content.

According to Flagan and Seinfeld (1988), the oxidation rate of hydrocarbons like CH 4 increases when combustion parameters are maintained at optimum levels. CH 4 oxidation rates are expected to decrease and emissions are expected to increase when combustion conditions do not allow for complete mixing of fuel and air, or when oxidation reactions are quenched early in the combustion process. In general, boiler parameters or operating conditions that result in an increase in CO concentrations are also likely to lead to increases in CH 4 . As discussed earlier, both CO

concentrations and CH 4 emissions at sources FBB1 and YCB1 were higher than those observed at the

other sources.

The formation of N 2 O within a boiler is a more complicated process. N 2 O emissions depend on fuel nitrogen content and combustion parameters like temperature, excess air, boiler load, and catalytic activity of char and mineral matter. N 2 O emissions, if attributed purely to fuel nitrogen content, would exhibit the following order: emissions from coal > lignite > peat > wood (Leckner 1998). The difference between wood/wood residuals/bark and kraft pulping liquor, as it relates to the potential to generate N 2 O emissions, is not clear. It has been shown that most of the nitrogen in wood is transferred to the black liquor during kraft pulping. As a consequence, fuel nitrogen is not expected to be the contributing factor of the differential in N 2 O emissions observed between solid biomass fuels and kraft pulping liquor in this study (Veverka et al. 1993).

While several combustion parameters can have minor effects on N 2 O formation, changes in combustion temperature are expected to have the most dramatic impact. Studies have established that

N 2 O formation peaks around 700 ° C. On the other hand, combustion temperatures below 500 ° C and

above 950 ° C prevent the formation of N 2 O (Tsupari 2007). Although information on combustion zone temperatures was not available for the sources tested during this study, they were expected to be higher than 950oC and therefore not expected to be a factor. This parameter is potentially more important in fluidized bed boilers, where boiler temperatures can be lower than 950 ° C (Fortum 2001,
Bonn, Pelz, and Baumann 1995).

As discussed above, several parameters can influence the formation of CH 4 and N 2 O during combustion. A study that correlates CH 4 and N 2 O emissions to these parameters would involve a more comprehensive testing plan that encompasses varying ranges of these parameters, in conjunction with the ability to reliably measure these variations. Such an analysis is beyond the scope of this study.

To the extent that fuel characteristics may dictate the efficiency of combustion and any related combustion parameters, the co-firing of fossil fuels along with biomass may also have an impact on

both CH 4 and N 2 O emissions. This study was geared towards developing emission factors for biomass firing and not intended to investigate the impact of co-firing. As discussed earlier, all the boilers included in this study were predominantly burning biomass fuels. In the case of boilers that co-fired No. 6 fuel oil, heat inputs from oil were ~ 10% and not variable enough to develop trends in emissions. The impact of co-firing can be better investigated by carrying out tests with varying levels of co-firing.26 Technical Bulletin No. 998

National Council for Air and Stream Improvement 5.3 Existing Emission Factors

In the GHGRR, EPA mandates the use of specific emission factors when quantifying the emissions of

CH 4 and N 2 O due to the burning of solid biomass fuels and kraft pulping liquors in boilers and recovery furnaces, respectively. These factors were derived primarily from previously reported values by the IPCC and WRI/WBCSD, two of the most prominent international agencies studying GHG
emissions and compiling available emission factors. Table 5.1 reproduces currently available 

### CH 4 and 

### N 2 

### O emission factors published by WRI/WBCSD and Tier 1 factors from IPCC (WRI/WBSCD 2005, IPCC 2006). These factors are reported in kilogram per terajoule (kg/TJ) and utilize a low heating value (LHV).

Table 5.1 WRI/WBCSD and IPCC Emission Factors

kg kg Emission Factor Description CH 4 /TJ N 2 O/TJ Reference

Wood waste

- fired boilers

Wood, wood waste, and other biomass and

wastes 30 4 Tier 1

– IPCC 2006

Uncontrolled emissions from wood

- fired stoker

boilers 15

- Tier 2 – IPCC 1997

Average for wood residue combustion 9.5 a 5.9 a USEPA 2001 Average for circulating fluidized bed boilers burning peat or bark 1 8.8 Fortum 2001

A verage for bubbling fluidized bed boilers burning peat or bark 2 b <2 Fortum 2001

Pre

- 1980 wood residue

- fired stoker boilers sampled

ahead of control devices 8.2 a

- NCASI 1980

Pre

- 1980 wood residue

- fired stoker boilers sampled

after wet scrubbers 2.7 a

- NCASI 1985

Wood

- fired boiler 41 c 3.1 c JPA 2001

Wood as fuel 24 c 3.4 c AEA Tech. 2001

Wood waste 30 5 Swedish EPA 2004 WRI Median emission factors for wood waste 12 4

1 – 40 1.4 – 75 EEA 2004 Recovery furnaces

Sul f ite lyes (Bla ck Liquor) 3 2 Tier 1

– IPCC 2006 Recovery furnace <1 <1 Fortum 2001 Recovery furnace – black liquor 2.5 d

- JPA 2001 Black liquor 30 5 Swedish EPA 2004 WRI Median emission factors for black liquor 2.5 2

1 – 17.7 1 – 21.4 EEA 2004

a Converted from GCV to NCV assuming a 5% difference.

b Excludes one very high number associated with low oxygen-high carbon monoxide conditions.

c Based on heat content of 20 GJ/t dry solids.

d Based on liquor heat content of 13.3 GJ/t dry solids.Technical Bulletin No. 998 27

National Council for Air and Stream Improvement As discussed earlier, there is significant variability in the emission factors provided in Table 5.1. Additional factors, besides fuel and operating parameters, may have contributed to this variability in previously reported emission factors. Some of these factors have been estimated based on limited data or data derived from measurements that utilized improper sampling techniques (Fortum 2001; Muzio et al. 1989). An example of an improper sampling technique would be the collection of an unconditioned grab sample that is subsequently shipped off-site for analysis. It has been shown that

N 2 O can be generated within a collection vessel from compounds typically found in combination boilers and recovery furnaces. Therefore, any emission factors for N 2 O that are derived from improperly conditioned grab samples are likely to overestimate actual emissions. Appendix C provides an example of this artifact formation along with a more detailed discussion of the

mechanism.

IPCC has taken these considerations into account and has estimated the uncertainties in its

measurements. For CH 4, it estimates an uncertainty range of 50% to 150%, while the uncertainty

associated with N 2 O measurement is an order of magnitude higher.

To compare the results of our study with previously published emission factors, the IPCC and WRI/WBCSD factors must first be converted to kg/MMBtu and then adjusted from a LHV to a HHV. This adjustment can be made using the assumption that there is a 5% difference in heat values for biomass fuels. The IPCC, WRI/WBCSD, and EPA factors do not distinguish between DCE and NDCE recovery furnaces. Consequently, for purposes of comparison, the existing emission factors have been assumed to apply to both recovery furnace categories. Methane and nitrous oxide emission factors are shown in Tables 5.2 and 5.3, respectively.

Table 5.2 CH 4 Emissions, kg/MMBtu

IPCC a,d WRI/WBCSD

GHG Protocol b,d EPA c NCASI Study

Mean (%RSD) NCASI Study (range)

Biomass

- fired

boilers 0.032 0.012 0.032 0.0049 (232%) ND<[0.00012] –

0.046

Non

- DCE

furnaces e 0.0030 0.00 25 0.030 0.0014 (117%) 0.000042 – 0.0031

DCE furnaces e 0.0030 0.00 25 0.030 0.0024 (187%) 0.00011 – 0.010

a IPCC (2006).

b WRI/WBCSD (2005).

c Emission factors mandated for use in GHG Inventories (USEPA 2009).

d Factors are converted from LHV to HHV assuming a 5% difference.

e DCE and NDCE furnaces have the same emission factors. EPA mandates the use of a single emission factor

for kraft pulping liquor (North American Softwood).28 Technical Bulletin No. 998

National Council for Air and Stream Improvement Table 5.3 N 2 O Emissions, kg/MMBtu

IPCC a WRI/WBCSD

GHG Protocol b,d EPA c NCASI Study

Mean (%RSD) NCASI Study (range)

Biomass

- fired

boilers 0.0042 0.0042 0.0042 0.0019 (61%) 0.00073 – 0.0034

Non

- DCE

furnaces e 0.0020 0.0020 0.0050 0.00044 (79%) 0.00015 – 0.00 082

DCE furnaces e 0.0020 0.0020 0.0050 0.00036 (57%) 0.00019 – 0.00065

a IPCC (2006).

b WRI/WBCSD (2005).

c Emission factors mandated for use in GHG Inventories (USEPA 2009).

d Factors are converted from LHV to HHV assuming a 5% difference.

e DCE and NDCE furnaces have the same emission factors. EPA mandates the use of a single emission factor

for kraft pulping liquor (North American Softwood).

As indicated in Tables 5.2 and 5.3, the emission factors for CH 4 and N 2 O developed during this study are lower than those mandated by EPA for these three source categories. The CH 4 and N 2 O emission factors developed during this study for biomass boilers are substantially lower than the EPA, IPCC, and WRI/WBCSD factors. In the case of kraft pulping liquors, CH 4 and N 2 O emission factors developed during this study are over an order of magnitude lower than EPA mandated factors.

6.0 CONCLUSIONS

An NCASI review of more recent literature indicates a dearth of accurate and direct emission

measurements of CH 4 and N 2 O from biomass-fired boilers and kraft recovery furnaces. As a result, the validity of existing emission factors, including those mandated by EPA in the GHG reporting rule, has come under scrutiny. Given the emphasis being placed on GHG inventories, the limited data availability, and uncertainty surrounding currently available emission factors, NCASI carried out a study to develop additional data for CH 4 and N 2 O emissions from these sources.

As part of the NCASI testing study, CH 4 and N 2 O stack concentrations were measured using a portable FTIR spectrometer. When the sample stream was properly conditioned, the FTIR provided reliable analysis for the target analytes with acceptable detection limits. Quality assurance results confirmed the accuracy of the analysis. Additionally, CH 4 data from the 2009 Boiler MACT/CISWI testing were gathered and incorporated into the study.

NCASI conducted emission measurements at 13 sources, including five wood-fired combination boilers, five DCE recovery furnaces, and three NDCE recovery furnaces. From the 2009 Boiler MACT/CISWI testing program, CH 4 data from 19 boilers and three CISWI units were also incorporated into this study. For wood/biomass fired boilers, the mean and median CH 4 emission factors were 0.0049 kg/MMBtu and 0.0012 kg/MMBtu, respectively. CH 4 emissions from two of these boilers were approximately five times larger than those observed at the other sources and contributed to the higher mean emission factors as compared to the median. The higher CH 4 emissions could be explained by the higher CO concentrations observed on these sources. The mean

and median N 2 O emission factors for wood/biomass fired boilers were 0.0019 kg/MMBtu and 0.0015 kg/MMBtu, respectively. For DCE recovery furnaces, mean and median CH 4 emission factors were 0.0024 kg/MMBtu and 0.00020 kg/MMBtu, respectively. The mean and median N 2 O emissionTechnical Bulletin No. 998 29

National Council for Air and Stream Improvement factors were 0.00036 kg/MMBtu and 0.00027 kg/MMBtu, respectively. For NDCE recovery
furnaces, the mean and median CH 4 emission factors were 0.0014 kg/MMBtu HHV and 0.00093 kg/MMBtu, respectively. The mean and median N 2 O emission factors were 0.00044 kg/MMBtu and 0.00034 kg/MMBtu, respectively.

The emission factors for CH 4 and N 2 O developed during this study are lower than those mandated by EPA for use in GHG inventories for these three source categories. The CH 4 and N 2 O emission factors developed during this study for biomass boilers are substantially lower than the EPA, IPCC, and WRI/WBCSD factors. In the case of kraft pulping liquors, CH 4 and N 2 O emission factors developed during this study for DCE and NCDE recovery furnaces are over an order of magnitude lower than

EPA mandated factors.

REFERENCES

AEA Technology. 2001. UK greenhouse gas inventory 1990

– 1999: Annual report for submission under the Framework Convention on Climate Change . Oxfordshire, England: AEA Technology National Environmental Technology Centre.

American Society for Testing and Materials (ASTM). 2003. Standard Test Method D 6348-03 – Determination of gaseous compounds by extractive direct interface Fourier transform infrared (FTIR) spectroscopy. West Conshohocken, PA: American Society for Testing and Materials.

Bonn, B., Pelz, G., and Baumann, H. 1995. Formation and decomposition of N 2 O in fluidized bed

boilers. Fuel 74:165-171. http://dx.doi.org/10.1016/0016-2361(95)92650-U

European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission inventory guidebook 3 rd

ed., September 2004 update. Copenhagen: European Environment Agency.

Flagan, R.C., and Seinfeld, J.H. 1988. Fundamentals of air pollution engineering. Englewood Cliffs,

NJ: Prentice Hall.

Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the Finnish energy production . Fortum, Finland: Fortum Power and Heat Oy.

Intergovernmental Panel on Climate Change (IPCC). 1996. Climate change 1995, the science of climate change . New York, NY: Cambridge University Press.

——— . 1997. Revised 1996 IPCC guidelines for national greenhouse gas inventories: Reference

manual (Vol. 3). IPCC National Greenhouse Gas Inventory Program.

___________. 2006. 2006 IPCC Guidelines for national greenhouse gas inventories . Hayama, Kanagawa, Japan: Intergovernmental Panel on Climate Change, Institute for Global Environmental Strategies.

Japan Paper Association (JPA). 2002. Various personal communications between JPA and Reid Miner of NCASI. Tokyo: Japan Paper Association.

Leckner, B. 1998. Fluidized bed combustion: Mixing and pollutant limitation. Progress in Energy

and Combustion Science 24:31-61. http://dx.doi.org/10.1016/S0360-1285(97)00021-X

Muzio, L.J., Teague, M.E., Kramlich, J.C., Cole, J.A., McCarthy, J.M., and Lyon, R.K. 1989. Errors in grab sample measurements of N 2 O from combustion sources. Journal of the Air Pollution

Control Association 39:287-293.

National Council [of the Paper Industry] for Air and Stream Improvement, Inc. (NCASI). 1980. A study of wood-residue fired power boiler total gaseous non-methane organic emissions in the30 Technical Bulletin No. 998

National Council for Air and Stream Improvement Pacific Northwest . Air Quality Technical Bulletin No. 109. New York: National Council of the Paper Industry for Air and Stream Improvement, Inc.

——— . 1985. Volatile organic carbon emissions from wood residue fired power boilers in the Southeast. Technical Bulletin No. 455. New York: National Council of the Paper Industry for Air and Stream Improvement, Inc.

——— . 2009a. Revised statistical data treatment procedures for pulp and paper mill 'air toxic'

emissions data. In SARA handbook (04.F.01). Research Triangle Park, NC: National Council for Air and Stream Improvement, Inc.

——— . 2009b. Appendix A: An overview of the steps and statistical procedures used to develop air emissions factors for the wood products industry. In SARA handbook (03.B.24). Research Triangle Park, NC: National Council for Air and Stream Improvement, Inc.

Swedish Environmental Protection Agency (Swedish EPA). 2004. Sweden ’ s national inventory report

2004

– Submitted under the United National Convention on Climate Change . Stockholm: Swedish Environmental Protection Agency.

Tsupari, E., Monni, S., Tormonen, K., Pellikka, T., and Syri, S. 2007. Estimation of annual CH 4 and

N 2 O emissions from fluidized bed combustion: An advance measurement-based method and its application to Finland

. International Journal of Greenhouse Gas Control 1:289-297. http://dx.doi.org/10.1016/S1750-5836(07)00019-9

United States Environmental Protection Agency (USEPA). 1999. Method 320 – Measurement of vapor phase organic and inorganic emissions by extractive Fourier Transform Infrared (FTIR) spectroscopy. Part 63, Appendix A. Federal Register 64(113): 31937-31951. June 14.

——— . 2000. 40 CFR Part 60, 61, and 63 Amendments for testing and monitoring provisions; final

rule. Federal Register 65(201): 61743-62273. October 17. http://www.gpo.gov/fdsys/pkg/FR2000-10-17/pdf/FR-2000-10-17.pdf

——— . 2001. AP-42 emission factors for wood residue combustion in boilers

– Supplement G, July

2001 . Washington, DC: United States Environmental Protection Agency.

——— . 2009. Mandatory Reporting of Greenhouse Gases. (40 CFR Part 98). Federal Register
74(209): 56260-56519.

Veverka, P.J., Nichols, K.M., Horton, R.R., and Adams, T.N. 1993. On the form of nitrogen in wood and its fate during kraft pulping . IPST Technical Paper Series Number 460. Atlanta, GA: Institute of Paper Science and Technology.

The World Research Institute and The World Business Council for Sustainable Development
(WRI/WBCSD). 2005. Calculation tools for estimating greenhouse gas emissions from pulp and paper mills . Report version 1.1. The World Resource Institute and The World Business Council for Sustainable Development Greenhouse Gas Protocol Initiative.A1



### APPENDIX A

DETAILED SOURCE RESULTSTable A1 Run Data for Source ARF3

Test Parameters

Date 1/13/2009 1/14/2009 1/14/2009 1/14/2009 1/15/2009
Stack Pressure (in. Hg) 29.68 30.06 30.03 29.96 30.17
Stack Temperature (° F) 321 318 318 319 333

Percent O 2 (%) 5.80 6.85 6.40 6.85 6.70

Percent CO 2 (%) 14.25 13.65 14.05 13.65 13.95

Percent H 2 O (%) 33.77 33.81 34.65 33.88 34.21
Stack Velocity (ft/sec) 67.24 60.81 60.12 60.33 66.62

Stack Flow Rate (acfm) 184922 167220 165322 165920 183198

Stack Flow Rate (dscfm) 82065 75459 73595 74471 80869

Run Number 1 2 3 4 5 6 7 8 9 10

BLS Fired (lb/hr) 81343 81759 75040 75000 75012 74981 74958 74978 81757 71785
BLS Heat Input (MMBtu/hr) 465.4 467.7 429.3 429.1 429.1 429.0 428.8 429.0 467.7 467.9
Oil Heat Input (MMBtu/hr) 33.2 32.5 0 0 37.0 37.0 15.5 16.3 0 0
Total Input (MMBtu/hr) 498.6 500.2 429.3 429.1 466.1 466.0 444.3 445.2 467.7 467.9

CH 4 Results

Concentration (ppmvd) 0.79 3.65 0.50 0.68 1.04 0.90 0.63 0.43 ND[0.65] 1.36

Mass Emission (lb/hr) 0.16 0.75 0.09 0.13 0.19 0.16 0.12 0.08 ND[0.13] 0.27

Production Based

Emission (kg/MMBtu) 0.00015 0.00068 0.00010 0.00014 0.00019 0.00016 0.00012 0.00008 ND[0.00013] 0.00027

Number of Detects 21/30 25/30 7/30 9/30 15/30 17/30 2/30 3/30 0/30 17/30
Spike Recovery (%) 100.4 85.0 95.8 82.3 91.9

N 2 O Results

Concentration (ppmvd) 0.84 0.63 0.51 0.53 0.72 0.55 0.46 0.25 0.50 0.29

Mass Emission (lb/hr) 0.47 0.36 0.26 0.28 0.36 0.28 0.24 0.13 0.27 0.16

Production Based

Emission (kg/MMBtu) 0.00043 0.00032 0.00028 0.00029 0.00035 0.00027 0.00024 0.00013 0.00027 0.00015

Number of Detects 30/30 24/30 40/40 27/30 29/30 28/30 27/30 23/30 30/30 15/30
Spike Recovery (%) 85.0 61.0 78.7 88.7 94.7Table A2 Analysis Method for Source ARF3

Method: GHG Mill A Recovery

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 9 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2231 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 37 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 41 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A3 Run Data for Source ABB2

Test Parameters

Date 7/8/2008 7/8/2008 7/8/2008

Stack Pressure (in. Hg) 29.86 29.82 29.82

Stack Temperature (° F) 144 141 135

Percent O 2 (%) 8.7 11.7 10.2

Percent CO 2 (%) 11.4 7.6 9.7

Percent H 2 O (%) 24.79 23.66 22.53

Stack Velocity (ft/sec) 50.36 50.93 51.32

Stack Flow Rate (acfm) 254419 257322 259251

Stack Flow Rate (dscfm) 167038 172107 177544

Run Number 1 2 3 4 5

Bark Fired (lb/hr) 53418 59728 51507 38639 41126

Bark Heat Input (MMBtu/hr) 427.3 477.8 412.1 309.1 329.0

CH 4 Results

Concentration (ppmvd) 1.0 2.1 3.2 2.6

Mass Emission (lb/hr) 0.42 0.88 1.38 1.15

Production Based Emission (kg/MMBtu) 0.00044 0.00083 0.0015 0.0016

Number of Detects 1/1 1/1 1/1 1/1

Spike Recovery (%)

N 2 O Results

Concentration (ppmvd) 1.52 1.3 1.74 2.32 2.25

Mass Emission (lb/hr) 1.74 1.49 2.06 2.74 2.74

Production Based Emission (kg/MMBtu) 0.0018 0.0014 0.0023 0.0040 0.0038

Number of Detects 5/5 5/5 5/5 5/5 5/5

Spike Recovery (%) 89.9 92.7 90.5 93.7Table A4 Analysis Method for Source ABB2

Method: GHG Mill A Bark Boiler (Cond)

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 9 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2146-2223 2570-2647

Nitric Oxide ppm Dry 12 23 1829-2020

Nitrogen Dioxide ppm Dry 5 37 2800-3000

Methane ppm Dry 6 14 2956-3203

Methanol ppm Dry 5 37 930-1120 2688-3159

-Pinene ppm Dry 3 39 2625-3250

-Pinene ppm Dry 4 37 2750-3105

Limonene ppm Dry 3 40 895-976 2748-3072

Oxygen % SensorTable A5 Run Data for Source BRF5

Test Parameters

Date 5/6/2008 5/6/2008 5/7/2008 5/7/2008 5/8/2008

Stack Pressure (in. Hg) 29.75 29.74 29.67 29.63 29.56

Stack Temperature (° F) 425 422 424 422 419

Percent O 2 (%) 6.9 6.5 8.8 7.0 7.0

Percent CO 2 (%) 12.4 12.5 11.3 11.0 10.5

Percent H 2 O (%) 28.01 27.74 25.96 25.41 26.79

Stack Velocity (ft/sec) 49.27 50.23 48.75 49.05 49.22

Stack Flow Rate (acfm) 376131 383488 372188 374435 375746

Stack Flow Rate (dscfm) 160605 164794 163163 165557 163221

Run Number 1 2 3 4 5

BLS Fired (lb/hr) 107488 112749 103360 87966 97390

BLS Heat Input (MMBtu/hr) 432.1 453.3 415.5 353.6 391.5

CH 4 Results

Concentration (ppmvd) 2.14 1.75 13.95 ND[0.85] 2.13

Mass Emission (lb/hr) 0.86 0.72 5.68 ND[0.30] 0.87

Production Based

Emission (kg/MMBtu) 0.00090 0.00072 0.0062 ND[0.00039] 0.0010

Number of Detects 24/30 18/30 30/30 0/30 22/30

Spike Recovery (%) 83.8 134.5 49.7 78.5

N 2 O Results

Concentration (ppmvd) 0.54 0.57 0.71 0.77 0.68

Mass Emission (lb/hr) 0.59 0.65 0.79 0.87 0.76

Production Based

Emission (kg/MMBtu) 0.00062 0.00065 0.00086 0.00111 0.00088

Number of Detects 23/30 24/30 5/30 27/30 29/30

Spike Recovery (%) 123.7 111.4 116.7 92.2 121.6Table A6 Analysis Method for Source BRF5

Method: GHG Mill B Recovery Boiler (Cond)

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 9 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2146-2223 2570-2647

Nitric Oxide ppm Dry 12 20 1829-2020

Nitrogen Dioxide ppm Dry 5 33 1552-1625 2800-3000

Methane ppm Dry 6 14 2771-3203

Hydrochloric Acid ppm Dry 4 28 2532-2879

Methanol ppm Dry 5 30 930-1120 2688-3159

Dimethyl Sulfide ppm Dry 1 34 903-1142 2725-3126

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A7 Run Data for Source CCB4

Test Parameters

Date 12/2/2008 12/4/2008 12/4/2008

Stack Pressure (in. Hg) 30.25 30.21 30.06
Stack Temperature (° F) 441 464 462

Percent O 2 (%) 9.0 8.5 9.5

Percent CO 2 (%) 11.5 11.8 10.3

Percent H 2 O (%) 15.13 18.76 16.18

Stack Velocity (ft/sec) 64.99 66.43 64.94

Stack Flow Rate (acfm) 196005 200346 195851

Stack Flow Rate (dscfm) 98436 93827 94395

Run Number 1 2 3 4 5 6

Bark Fired (lb/hr) 69980 66040 70300 74140 65080 58240
Bark Heat Input (MMBtu/hr) 329.9 313.2 335.0 350.2 316.2 274.9

Oil Fired (lb/hr) 2375 2391 2336 2348 1688 1685
Oil Heat Input (MMBtu/hr) 44.80 45.12 44.07 44.31 31.85 31.79

Total Heat Input (MMBtu/hr) 374.7 358.3 379.1 394.5 348.1 306.7

CH 4 Results

Concentration (ppmvd) 2.57 1.27 17.02 16.97 24.95 1.20

Mass Emission (lb/hr) 0.63 0.31 3.99 3.98 5.88 0.28

Production Based Emission (kg/MMBtu) 0.00076 0.00040 0.0048 0.0046 0.0077 0.00042

Number of Detects 8/8 5/5 8/8 5/5 8/8 5/5

Spike Recovery (%) 99.0 98.8 100.1

N 2 O Results

Concentration (ppmvd) 1.69 1.45 1.81 2.17 2.29 1.46

Mass Emission (lb/hr) 1.14 0.98 1.16 1.39 1.48 0.94

Production Based Emission (kg/MMBtu) 0.0014 0.0012 0.0014 0.0016 0.0019 0.0014

Number of Detects 8/8 5/5 8/8 5/5 8/8 5/5

Spike Recovery (%) 102.4 81.7 112.7Table A8 Analysis Method for Source CCB4

Method: GHG Mill C Combination

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 22 11 3200-3450

Carbon Dioxide % Dry 9 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2146-2223 2570-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A9 Run Data for Source DRF1

Test Parameters

Date 2/17/2009 2/17/2009
Stack Pressure (in. Hg) 29.97 29.83
Stack Temperature (° F) 378 379

Percent O 2 (%) 4.2 3.9

Percent CO 2 (%) 15.8 16.0

Percent H 2 O (%) 27.57 28.14
Stack Velocity (ft/sec) 64.44 65.49

Stack Flow Rate (acfm) 539888 548653

Stack Flow Rate (dscfm) 246690 247370

Run Number 1 2 3 4 5 6 7 8

BLS Fired (lb/hr) 228794 228575 228768 229131 228971 228156 227299 224790

BLS Heat Input (MMBtu/hr) 1401.4 1400.0 1401.2 1403.4 1402.4 1397.5 1390.2 1376.8

CH 4 Results

Concentration (ppmvd) 0.21 0.24 0.21 0.23 0.17 0.24 0.18 0.19

Mass Emission (lb/hr) 0.13 0.15 0.13 0.14 0.11 0.15 0.11 0.12

Production Based

Emission (kg/MMBtu) 0.000042 0.000047 0.000041 0.000046 0.000034 0.000047 0.000037 0.000038

Number of Detects 0/5 0/6 0/5 0/5 0/5 1/5 0/5 0/5
Spike Recovery (%) 93.0

N 2 O Results

Concentration (ppmvd) ND[0.45] 0.22 ND[0.33] ND[0.29] 0.33 0.32 ND[0.25] 0.31

Mass Emission (lb/hr) ND[0.77] 0.38 ND[0.55] ND[0.49 0.56 0.55 ND[0.43] 0.53

Production Based

Emission (kg/MMBtu) ND[0.00023] 0.00012 ND[0.00018] ND[0.00016] 0.00018 0.00018 ND[0.00014] 0.00017

Number of Detects 0/5 1/6 0/5 0/5 3/5 4/5 0/5 2/5
Spike Recovery (%) 85.6 81.5 80.2 76.2Table A10 Analysis Method for Source DRF1

Method: GHG Mill D

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 9 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2231 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 37 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 41 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A11 Run Data for Source DBB1

Test Parameters

Date 2/18/2009 2/18/2009 2/18/2009 2/19/2009 2/19/2009

Stack Pressure (in. Hg) 29.57 29.48 29.41 30.12 30.14
Stack Temperature (° F) 326 330 330 304 304

Percent O 2 (%) 11.6 12.3 11.9 12.9 13.5

Percent CO 2 (%) 8.4 8.2 8.6 7.2 7.0

Percent H 2 O (%) 15.16 14.90 14.99 12.92 11.59

Stack Velocity (ft/sec) 66.64 74.60 73.50 59.55 60.41

Stack Flow Rate (acfm) 263889 295393 291057 235819 239197

Stack Flow Rate (dscfm) 148510 165580 162413 142896 147158

Run Number 1 2 3 4 5 6 7 8 9 10

Bark Fired (lb/hr) 102643 94210 103480 103272 105986 111673 88132 66489 88325 88904

Bark Heat Input (MMBtu/hr) 461.9 423.9 465.7 464.7 476.9 502.5 396.6 299.2 397.5 400.1

CH 4 Results

Concentration (ppmvd) 0.61 1.18 0.42 0.49 0.58 1.27 0.61 0.55 0.56 0.57

Mass Emission (lb/hr) 0.23 0.44 0.17 0.20 0.24 0.51 0.22 0.20 020 0.21

Production Based

Emission (kg/MMBtu) 0.00022 0.00047 0.00017 0.00020 0.00022 0.00046 0.00025 0.00030 0.00023 0.00024

Number of Detects 6/6 5/5 4/5 6/6 5/5 6/6 7/7 5/5 5/5 5/5

Spike Recovery (%) 97.3 97.7 94.5 95.5 92.9 99.7 98.2 94.3 94.0 91.7

N 2 O Results

Concentration (ppmvd) 0.91 1.16 1.00 0.81 1.15 1.18 ND[0.55] 0.86 0.86 ND[0.62]

Mass Emission (lb/hr) 0.93 1.18 1.13 0.92 1.28 1.32 ND[0.54] 0.84 0.86 ND[0.62]

Production Based

Emission (kg/MMBtu) 0.0009 0.0013 0.0011 0.0009 0.0012 0.0012 ND[0.0006] 0.0013 0.0010 ND[0.0007]

Number of Detects 6/6 5/5 5/5 6/6 5/5 6/6 0/5 5/5 5/5 0/5

Spike Recovery (%) 87.9 96.4 91.0 90.6 87.6 92.0 87.0 91.1Table A12 Analysis Method for Source DBB1

Method: GHG Mill D

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 9 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2231 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 37 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 41 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A13 Run Data for Source ERF1

Test Parameters

Date 2/24/2009 2/24/2009 2/25/2009

Stack Pressure (in. Hg) 30.47 30.37 30.46

Stack Temperature (° F) 374 376 378

Percent O 2 (%) 4.1 3.7 3.9

Percent CO 2 (%) 15.1 15.4 14.9

Percent H 2 O (%) 24.80 24.80 24.90

Stack Velocity (ft/sec) 87.28 87.34 89.06

Stack Flow Rate (acfm) 497680 497993 507841

Stack Flow Rate (dscfm) 241344 240244 244881

Run Number 1 2 3 4 5 6 7 8 9 10

BLS Fired (lb/hr) 173298 173339 173323 173758 174545 174641 166068 166295 166472 175097

BLS Heat Input (MMBtu/hr) 947.9 948.2 948.1 950.6 954.8 955.3 908.4 909.6 910.6 957.8

CH 4 Results

Concentration (ppmvd) 0.23 4.38 19.42 9.98 3.07 17.87 10.83 13.39 7.61 19.82

Mass Emission (lb/hr) 0.14 2.64 11.71 6.02 1.84 10.73 6.63 8.19 4.66 12.12

Production Based

Emission (kg/MMBtu) 0.00007 0.0013 0.0056 0.0029 0.0009 0.0051 0.0033 0.0041 0.0023 0.0057

Number of Detects 1/10 5/5 6/6 5/5 5/5 5/5 7/7 5/5 6/6 5/5

Spike Recovery (%) 96.8 101.3 98 97.8 98.5 97.5 97.7 98.2 102.3

N 2 O Results

Concentration (ppmvd) ND[0.13] ND[0.24] ND[0.65] ND[0.38] ND[0.21] ND[0.66] 0.77 ND[0.53] 0.78 0.34

Mass Emission (lb/hr) ND[0.21] ND[0.39] ND[1.08] ND[0.63] ND[0.35] ND[1.08] 1.29 ND[0.89] 1.30 0.57

Production Based

Emission (kg/MMBtu) ND[0.0001] ND[0.00019] ND[0.00051] ND[0.0003] ND[0.00016] ND[0.00051] 0.00065 ND[0.00044] 0.00065 0.00027

Number of Detects 0/10 0/5 0/6 0/5 0/5 0/6 2/7 0/5 6/6 1/5

Spike Recovery (%) 85.3 87.9 126.6Table A14 Analysis Method for Source ERF1

Method: GHG Mill E

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 9 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 19 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2146-2215 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 37 2800-3000

Methane ppm Dry 6 14 2956-3203

Oxygen % SensorTable A15 Run Data for Source FRF1

Test Parameters

Date 3/28/2009 3/28/2009

Stack Pressure (in. Hg) 29.35 29.26 Stack Temperature (° F) 316 316

Percent O 2 (%) 6.9 7.2

Percent CO 2 (%) 12.1 12.5

Percent H 2 O (%) 34 .26 33.22 Stack Velocity (ft/sec) 40.88 40.91

Stack Flow Rate (acfm) 87765 87845

Stack Flow Rate (dscfm) 38485 39036

Run Number 1 2 3 4 5 6

BLS Fired (lb/hr) 31680 31803 31957 31737 31562 31285 BLS Heat Input (MMBtu/hr) 186.9 187.6 188.5 187. 2 186.2 184.6

CH 4 Results

Concentration (ppmvd) 60.01 67.12 42.18 25.87 8.40 62.72

Mass Emission (lb/hr) 5.77 6.45 4.05 2.52 0.82 6.12

Production Based Emission (kg /MMBtu) 0.0140 0.0156 0.0098 0.0061 0.0020 0.0150

Number of Detects 5/ 5 5/5 6/6 7/7 6/6 5/5 Spike Recovery (%) 97.8 99.4 99.3 99.5

N 2 O Results

Concentration (ppmvd) 1.13 1.33 0.69 0 .83 1.06 1.05

Mass Emission (lb/hr) 0.30 0.35 0.18 0.22 0.28 0.28

Production Based Emission (kg /MMBtu) 0.00072 0.00085 0.00044 0.00054 0.00069 0.00069

Number of Detects 5/5 5/5 6/6 7/7 6/6 5/5 Spike Recovery (%) 112.9 97.9 91.9 105.1Table A16 Analysis Method for Source FRF1

Method: GHG Mill F

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2215 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 42 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A17 Run Data for Source FRF3

Test Parameters

Date 3/25/2009 3/25/2009 3/26/2009

Stack Pressure (in. Hg) 29.63 29.58 29.68

Stack Temperature (° F) 318 318 305

Percent O 2 (%) 7.3 7.2 9.0

Percent CO 2 (%) 12.8 12.8 10.6

Percent H 2 O (%) 30.56 32.64 30.25

Stack Velocity (ft/sec) 65.43 65.55 64.57

Stack Flow Rate (acfm) 137030 137284 135242

Stack Flow Rate (dscfm) 63957 62039 64577

Run Number 1 2 3 4 5 6 7 8 9

BLS Fired (lb/hr) 53174 53237 53408 52703 51262 51797 46136 46470 46246

BLS Heat Input (MMBtu/hr) 313.7 314.1 315.1 311.0 302.5 305.6 272.2 274.2 272.9

CH 4 Results

Concentration (ppmvd) 3.34 2.48 4.95 6.84 6.51 6.69 1.52 0.98 7.84

Mass Emission (lb/hr) 0.53 0.40 0.79 1.06 1.01 1.04 0.24 0.16 1.26

Production Based Emission (kg/MMBtu) 0.00077 0.00057 0.00114 0.00155 0.00151 0.00154 0.00041 0.00026 0.00210

Number of Detects 6/6 5/5 6/6 5/5 5/5 6/6 6/6 5/5 5/5

Spike Recovery (%) 98.9 98.1 99.3 98.3 99.6 99.9 93.4 98.0

N 2 O Results

Concentration (ppmvd) 0.71 0.70 0.77 0.79 0.66 0.95 0.54 0.46 1.03

Mass Emission (lb/hr) 0.31 0.31 0.34 0.34 0.28 0.40 0.24 0.20 0.46

Production Based Emission (kg/MMBtu) 0.00045 0.00044 0.00049 0.00049 0.00042 0.00060 0.00039 0.00034 0.00076

Number of Detects 6/6 5/5 6/6 5/5 5/5 6/6 6/6 5/5 5/5

Spike Recovery (%) 90.0 94.3 96.2 93.2 91.9 93.6 94.5 89.0Table A18 Analysis Method for Source FRF3

Method: GHG Mill F

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2215 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 42 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A19 Run Data for Source FBB1

Test Parameters

Date 3/23/2009 3/24/2009 3/24/2009

Stack Pressure (in. Hg) 29.71 29.79 29.62

Stack Temperature (° F) 147 143 145

Percent O 2 (%) 6.8 8.7 6.9

Percent CO 2 (%) 10.3 9.7 12.4

Percent H 2 O (%) 23.73 21.12 22.25

Stack Velocity (ft/sec) 30.29 29.76 32.37

Stack Flow Rate (acfm) 172724 169690 184570

Stack Flow Rate (dscfm) 113795 116671 123963

Run Number 1 2 3 4 5 6 7 8 9 10

Bark Fired (lb/hr) 118414 105743 114525 125992 99798 88599 126158 129422 126124 132670

Bark Heat Input (MMBtu/hr) 503.3 449.4 486.7 535.5 424.1 376.6 536.2 550.0 536.0 563.9

CH 4 Results

Concentration (ppmvd) 210.82 272.91 89.66 236.14 53.40 49.68 216.26 108.27 204.81 108.66

Mass Emission (lb/hr) 59.93 77.58 26.13 68.83 15.56 14.48 66.97 33.53 63.43 33.65

Production Based

Emission (kg/MMBtu) 0.054 0.078 0.024 0.058 0.017 0.017 0.057 0.028 0.054 0.027

Number of Detects 5/5 5/5 5/5 6/6 6/6 6/6 6/6 5/5 5/5 6/6

Spike Recovery (%) 101.3 100.2 101.5 99.8 99.6 97.7 100.5 101.2

N 2 O Results

Concentration (ppmvd) 0.76 0.85 0.37 ND[0.61] 1.58 2.37 ND[0.61] 0.98 0.42 0.96

Mass Emission (lb/hr) 0.59 0.66 0.30 ND[0.48] 1.26 1.90 ND[0.51] 0.83 0.36 0.82

Production Based

Emission (kg/MMBtu) 0.00054 0.00067 0.00028 ND<[0.00041] 0.00135 0.00229 ND[0.00043] 0.00069 0.00030 0.00066

Number of Detects 2/5 5/5 1/5 0/6 6/6 6/6 0/6 5/5 1/5 6/6

Spike Recovery (%) 93.9 101.1 99.2 100.7 91.3 122.1Table A20 Analysis Method for Source FBB1

Method: GHG Mill F Bark Boiler

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2215 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethane ppm Dry 2 39 2663-3180

Acetylene ppm Dry 1 43 1219-1428 3095-3389

Ethylene ppm Dry 5 42 895-1134 2877-3180

Formaldehyde ppm Dry 5 38 2500-3211

Benzene ppm Dry 3 38 949-1096 2941-3172

Oxygen % SensorTable A21 Run Data for Source GRF1

Test Parameters

Date 6/11/2009 6/11/2009 6/11/2009

Stack Pressure (in. Hg) 29.82 29.77 29.75

Stack Temperature (° F) 329 330 329

Percent O 2 (%) 6.6 6.9 7.0

Percent CO 2 (%) 14.2 13.9 13.8

Percent H 2 O (%) 32.8 33.3 32.1

Stack Velocity (ft/sec) 94.21 94.86 94.28

Stack Flow Rate (acfm) 335070 337380 335322

Stack Flow Rate (dscfm) 150183 149616 151551

Run Number 1 2 3 4 5 6

BLS Fired (lb/hr) 120100 121800 121800 121800 118600 118500

BLS Heat Input (MMBtu/hr) 672.6 682.1 682.1 682.1 664.2 663.6

CH 4 Results

Concentration (ppmvd) 0.44 0.40 0.45 0.59 0.42 0.39

Mass Emission (lb/hr) 0.17 0.15 0.17 0.22 0.16 0.15

Production Based Emission (kg/MMBtu) 0.00011 0.00010 0.00011 0.00015 0.00011 0.00010

Number of Detects 0/5 0/5 0/5 2/5 0/5 0/5

Spike Recovery (%) 99.1

N 2 O Results

Concentration (ppmvd) 0.17 0.28 0.46 0.38 0.25 0.20

Mass Emission (lb/hr) 0.17 0.29 0.47 0.39 0.26 0.21

Production Based Emission (kg/MMBtu) 0.00012 0.00019 0.00031 0.00026 0.00018 0.00014

Number of Detects 2/5 5/5 5/5 5/5 5/5 5/5

Spike Recovery (%) 98.1 95.9 110.7 93.8 95.2Table A22 Analysis Method for Source GRF1

Method: GHG Mill G RF1

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2153-2207 2501-2601

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 42 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A23 Run Data for Source GRF2

Test Parameters

Date 6/9/2009 6/9/2009 6/9/2009

Stack Pressure (in. Hg) 29.74 29.69 29.68

Stack Temperature (° F) 306 312 317

Percent O 2 (%) 8.3 7.4 7.2

Percent CO 2 (%) 12.8 13.6 13.8

Percent H 2 O (%) 30.55 31.65 28.80

Stack Velocity (ft/sec) 155.06 157.73 157.8

Stack Flow Rate (acfm) 308726 314029 314177

Stack Flow Rate (dscfm) 146816 145521 150627

Run Number 1 2 3 4 5 6

BLS Fired (lb/hr) 96600 98850 105900 106400 107100 107250

BLS Heat Input (MMBtu/hr) 541.0 553.6 593.0 595.8 599.8 600.6

CH 4 Results

Concentration (ppmvd) 0.53 ND[0.68] 0.47 0.37 0.40 0.44

Mass Emission (lb/hr) 0.19 ND[0.25] 0.17 0.14 0.15 0.17

Production Based Emission (kg/MMBtu) 0.00016 ND[0.00020] 0.00013 0.00010 0.00011 0.00013

Number of Detects 3/30 0/30 14/30 7/30 12/31 15/30

Spike Recovery (%) 93.8 95.6

N 2 O Results

Concentration (ppmvd) 0.30 0.40 0.12 0.16 0.21 0.23

Mass Emission (lb/hr) 0.30 0.40 0.12 0.16 0.22 0.24

Production Based Emission (kg/MMBtu) 0.00026 0.00033 0.000092 0.00012 0.00017 0.00018

Number of Detects 29/30 30/30 11/30 18/30 27/31 25/30

Spike Recovery (%) 99.9 101.1 89.9Table A24 Analysis Method for Source GRF2

Method: GHG Mill G RF2

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2138-2207 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 42 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A25 Run Data for Source GCB3

Test Parameters

Date 6/10/2009 6/10/2009 6/10/2009

Stack Pressure (in. Hg) 29.85 29.81 29.81

Stack Temperature (° F) 146 147 148

Percent O 2 (%) 11.1 10.7 10.4

Percent CO 2 (%) 9.1 9.4 9.7

Percent H 2 O (%) 30.01 26.16 31.31

Stack Velocity (ft/sec) 73.29 72.75 75.04

Stack Flow Rate (acfm) 207433 205919 212387

Stack Flow Rate (dscfm) 126259 131835 126177

Run Number 1 2 3 4 5 6

Bark Fired (lb/hr) 61600 63333 67200 64800 64000 65200

Bark Heat Input (MMBtu/hr) 231.0 237.5 252.0 243.0 240.0 244.5

Oil Heat Input (MMBtu/hr) 0.0 1.5 2.0 6.0 1.0 0.5

Total Heat Input (MMBtu/hr) 231 239 254.0 249.0 241.0 245.0

CH 4 Results

Concentration (ppmvd) 1.59 1.09 1.27 0.94 1.04 0.92

Mass Emission (lb/hr) 0.50 0.34 0.42 0.31 0.33 0.29

Production Based Emission (kg/MMBtu) 0.00099 0.00065 0.00075 0.00056 0.00062 0.00054

Number of Detects 30/30 30/30 30/30 30/30 30/30 30/30

Spike Recovery (%) 101.3 99.0 102.3

N 2 O Results

Concentration (ppmvd) 1.20 1.48 2.22 2.25 2.96 2.41

Mass Emission (lb/hr) 1.04 1.28 2.01 2.04 2.56 2.08

Production Based Emission (kg /MMBtu) 0.0020 0.0024 0.0036 0.0037 0.0048 0.0038

Number of Detects 28/30 30/30 30/30 30/30 30/30 30/30

Spike Recovery (%) 101.1 109.3 100.3Table A26 Analysis Method for Source GCB3

Method: GHG Mill G CB3

Analyte List Unit Compensation References Interferences Analysis Area 1 Analysis Area 2

Water Vapor % Wet 21 10 3200-3450

Carbon Dioxide % Dry 14 7 2015-2215

Carbon Monoxide ppm Dry 20 6 2005-2177

Nitrous Oxide ppm Dry 6 5 2146-2200 2501-2647

Nitric Oxide ppm Dry 12 24 1829-2020

Nitrogen Dioxide ppm Dry 5 38 2800-3000

Methane ppm Dry 6 14 2956-3203

Ethylene ppm Dry 5 42 895-1134 2877-3180

Sulfur Dioxide ppm Dry 6 23 1057-1259 2439-2550

Oxygen % SensorTable A27 Run Data for Source HCB1

Test Parameters

Date 7/15/09 7/15/09 7/15/09

Stack Flow Rate (dscfm) 86591 76897 73169

Run Number 1 2 3

Bark (%) 88.8 88.8 88.8

Resin Wood (%) 11.2 11.2 11.2

Natural Gas (%) 0.0 0.0 0.0
Total Heat Input (MMBtu/hr) 270.1 263.5 246.2

CH 4 Results

Concentration (ppmvd) ND[0.33] ND[0.34] ND[0.34]

Mass Emission (lb/hr) ND[0.072] ND[0.064] ND[0.062]

Production Based Emission (kg /MMBtu) ND[0.00012] ND[ 0.00011] ND[0.00011]

Table A28 Run Data for Source ICB1

Test Parameters

Date 7/14/09 7/15/09 7/15/09

Stack Flow Rate (dscfm) 54929 55114 56963

Run Number 1 2 3 Hog Fuel (%) 80.1 78.3 70.4 Municipal Solid Waste (%) 19.8 20.6 21.7

Natural Gas (%) 0.0 1.1 8.0 Total Heat Input (MMBtu/hr) 207.6 204.5 216.5

CH 4 Results

Concentration (ppmvd) 6.0 5.2 6.6

Mass Emission (lb/hr) 0.82 0.72 0.94

Production Based Emission (kg /MMBtu) 0.0018 0.0016 0.0020Table A29 Run Data for Source JCB2

Test Parameters

Date 7/1/09 7/2/09 7/2/09

Stack Flow Rate (dscfm) 160000 160000 160000

Run Number 1 2 3

Bark (%) 81.5 81.5 81.5

TDF (%) 18.0 18.0 18.0

Fuel Oil (%) 0.6 0.6 0.6

Total Heat Input (MMBtu/hr) 577.3 548.4 5 84.5

CH 4 Results

Concentration (ppmvd) 27.6 11.3 33.5

Mass Emission (lb/hr) 11.03 4.52 13.39

Production Based Emission (kg/MMBtu) 0.0087 0.0037 0.0104

Table A30 Run Data for Source KCB2

Test Parameters

Date 8/4/09 8/4/09 8/4/09

Stack Flow Rate (dscfm) 24393 24080 24168

Run Number 1 2 3

Bark (MMBtu/hr) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 90.5 92.7 81.3

CH 4 Results

Concentration (ppmvd) 2.0 1.0 1.1

Mass Emission (lb/hr) 0.12 0.060 0.066

Pro duction Based Emission (kg /MMBtu) 0.00061 0.00029 0.00037Table A31 Run Data for Source LCB1

Test Parameters

Date 8/13/09 8/13/09 8/13/09

Stack Flow Rate (dscfm) 21242 23203 23075

Run Number 1 2 3

Wood/Bark (%) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 77.7 72.2 68.5

CH 4 Results

Concentration (ppmvd) 2.96 1.03 2.26

Mass Emission (lb/hr) 0.16 0.060 0.13

Production Based Emission (kg /MMBtu) 0.00092 0.00037 0.00086

Table A32 Run Data for Source MCB3

Test Parameters

Date 8/6/09 8/6/09 8/7/09

Stack Flow Rate (dscfm) 11098 11213 11090

Run Number 1 2 3

Wood Waste (%) 100.0 100.0 100.0
Total Heat Input (MMBtu/hr) 47.17 46.10 48.52

CH 4 Results

Concentration (ppmvd) 0.82 0. 92 1.87

Mass Emission (lb/hr) 0.023 0.026 0.052

Production Based Emission (kg /MMBtu) 0.00022 0.00025 0.00048Table A33 Run Data for Source NCB1

Test Parameters

Date 8/6/09 8/6/09 8/7/09

Stack Flow Rate (dscfm) 80214 76785 79123

Run Number 1 2 3

Bark (%) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 318.69 337.77 316.05

CH 4 Results

Concentration (ppmvd) 4.93 4.10 1.78

Mass Emission (lb/hr) 0.99 0.79 0.35

Production Based Emission (kg /MMBtu) 0.0014 0.0011 0.00 050

Table A34 Run Data for Source OCB4

Test Parameters

Date 8/11/09 8/11/09 8/12/09

Stack Flow Rate (dscfm) 128000 127000 130000

Run Number 1 2 3

Bark (%) 91.4 62.4 89.3

Fuel Oil (%) 6.1 21.6 5.9

Natural Gas (%) 2.5 16.0 4. 8
Total Heat Input (MMBtu/hr) 431.16 239.45 427.55

CH 4 Results

Concentration (ppmvd) 0.46 6.17 0.89

Mass Emission (lb/hr) 0.15 1.96 0.29

Production Based Emission (kg /MMBtu) 0.00015 0.00371 0.00031Table A35 Run Data for Source PCB4

Test Parameters

Date 8/5/09 8/5/09 8/6/09

Stack Flow Rate (dscfm) 85489 80039 82047

Run Number 1 2 3

Bark WWT Sludge

TDF Total Heat Input (MMBtu/hr) 337.1 351.0 338.9

CH 4 Results

Concentration (ppmvd) 0.6 0 0.61 0.77

Mass Emission (lb/hr) 0.13 0.12 0.16

Production Based Emission (kg /MMBtu) 0.00017 0.00016 0.00021

Table A36 Run Data for Source QCB8

Test Parameters

Date 7/29/2009 7/29/2009 7/30/2009

Stack Flow Rate (dscfm) 53777 54131 50798

Run Number 1 2 3 WWT Sludge (%) 62.0 62.0 62.0

Wood/Bark (%) 38.0 38.0 38.0 Total Heat Input (MMBtu/hr) 164.17 163.59 153.51

CH 4 Results

Concentration (ppmvd) 2.05 1.85 1.70

Mass Emission (lb/hr) 0.28 0.25 0.22

Production Bas ed Emission (kg /MMBtu) 0.00076 0.00069 0.00064Table A37 Run Data for Source RCB1

Test Parameters

Date 9/2/2009 9/2/2009 9/3/2009

Stack Flow Rate (dscfm) 7226 7128 7329

Run Number 1 2 3

Bark (%) 100.0 100.0 100.0

Total He at Input (MMBtu/hr) 27.92 26.47 23.29

CH 4 Results

Concentration (ppmvd) 12.2 2.2 1.3

Mass Emission (lb/hr) 0.22 0.039 0.024

Production Based Emission (kg /MMBtu) 0.00358 0.00067 0.00046

Table A38 Run Data for Source SCB1

Test Parameters

Date 8/14/2009 8/14/2009 8/14/2009

Stack Flow Rate (dscfm) 157931 159424 163355

Run Number 1 2 3

Bark (%) 68.8 68.4 68.2

Cross ties (%) 11.7 11.6 11.6

Natural Gas (%) 9.4 9.3 9.3 WWT Sludge (%) 5.9 6.2 6.2 Total Heat Input (MMBtu/hr ) 584.09 587.45 594.13

CH 4 Results

Concentration (ppmvd) 4.0 15.3 2.5

Mass Emission (lb/hr) 1.58 6.09 1.02

Production Based Emission (kg /MMBtu) 0.00123 0.00470 0.00078Table A39 Run Data for Source TCB1

Test Parameters

Dat e 8/11/2009 8/12/2009 8/12/2009

Stack Flow Rate (dscfm) 53484 48369 52952

Run Number 1 2 3

Wood (%) 100.0 100.0 100.0
Total Heat Input (MMBtu/hr) 182.02 139.73 159.86

CH 4 Results

Concentration (ppmvd) 1.59 4.24 6.39

Mass Emission ( lb/hr) 0.21 0.51 0.85

Production Based Emission (kg /MMBtu) 0.00053 0.00166 0.00240

Table A40 Run Data for Source UCB2

Test Parameters

Date 6/24/09 6/25/09 6/25/09

Stack Flow Rate (dscfm) 191210 190684 181706

Run Number 1 2 3

Wood/Bark (%) 77.2 78.2 83.0 WWT Sludge (%) 5.0 9.1 8.6

OCC R ejects (%) 17.0 11.9 7.6

Natural Gas (%) 0.8 0.8 0.8 Total Heat Input (MMBtu/hr) 725.32 765.32 590.23

CH 4 Results

Concentration (ppmvd) 16.7 8.0 2.14

Mass Emission (lb/hr) 7.98 3.81 0.97

Production Based Emission (kg /MMBtu) 0.00499 0.00226 0.00075Table A41 Run Data for Source VCB2

Test Parameters

Date 8/6/09 8/6/09 8/6/09

Stack Flow Rate (dscfm) 132000 128000 130000

Run Number 1 2 3

Bark (%) 61.6 61.6 61.6 WWT Sludge (%) 19.3 19.3 19.3

Cross T ies (%) 16.4 16.4 16.4

Natural Gas (%) 2.7 2.7 2.7 Total Heat Input (MMBtu/hr) 519.57 501.89 533.52

CH 4 Results

Concentration (ppmvd) 1.9 2.6 8.3

Mass Emission (lb/hr) 0.63 0.83 2.70

Product ion Based Emission (kg /MMBtu) 0.00055 0.00075 0.00229

Table A42 Run Data for Source WCB1

Test Parameters

Date 7/30/2009 7/31/2009 7/31/2009

Stack Flow Rate (dscfm) 159000 157000 173000

Run Number 1 2 3

Bark (%) 73.81 89.77 70 .08

OCC R ejects (%) 6.32 4.77 5.77

Natural Gas (%) 10.88 0.6 21.97 WWT Sludge (%) 8.99 3.85 3.18 Total Heat Input (MMBtu/hr) 534.70 573.22 654.91

CH 4 Results

Concentration (ppmvd) 3.8 4.4 3.1

Mass Emission (lb/hr) 1.51 1.73 1.34

Productio n Based Emission (kg /MMBtu) 0.00128 0.00137 0.00093Table A43 Run Data for Source XCB1

Test Parameters

Date 8/13/2009 8/13/2009 8/14/2009

Stack Flow Rate (dscfm) 46530 44430 44910

Run Number 1 2 3

Bark (%) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 168.87 175.30 176.05

CH 4 Results

Concentration (ppmvd) 17.9 13.1 10.5

Mass Emission (lb/hr) 2.08 1.45 1.18

Production Based Emission (kg /MMBtu) 0.0056 0.0038 0.0030

Table A44 Run Data for Source YCB1

Test Parameters

Date 8/6/2009 8/7/2009 8/7/2009

Stack Flow Rate (dscfm) 84245 85641 86904

Run Number 1 2 3

Bark (%) 92.9 94.4 92.6

Natural Gas (%) 7.1 5.6 7.4 Total Heat Input (MMBtu/hr) 373.68 353.90 362.07

CH 4 Results

Conc entration (ppmvd) 189.54 205.80 119.34

Mass Emission (lb/hr) 39.89 44.03 25.91

Production Based Emission (kg /MMBtu) 0.048 0.056 0.032Table A45 Run Data for Source ZCB1

Test Parameters

Date 10/8/2009 10/8/2009 10/8/2009

Stack Flow Rate (dscfm) 15438 15576 14587

Run Number

Bark (%) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 15.66 16.44 15.86

CH 4 Results

Concentration (ppmvd) 4.11 3.95 3.24

Mass Emission (lb/hr) 0.16 0.15 0.12

Production Based Emission ( kg /MMBtu) 0.0046 0.0042 0.0034

Table A46 Run Data for Source AACB1

Test Parameters

Date 7/29/2009 7/30/2009 7/30/2009

Stack Flow Rate (dscfm) 11900 11900 9440

Run Number

Wood/Bark (%) 100.0 100.0 100.0 Total Heat Input (M MBtu/hr) 17.29 13.71 17.72

CH 4 Results

Concentration (ppmvd) 3.8 10.7 1.5

Mass Emission (lb/hr) 0.11 0.32 0.035

Production Based Emission (kg /MMBtu) 0.0030 0.0105 0.0009Table A47 Run Data for Source ABCB1

Test Parameters

Date 7/23/2009 7/23/2009 7/23/2009

Stack Flow Rate (dscfm) 13100 9680 11100

Run Number

Bark (%) 90.0 90.0 90.0

Wood (%) 10.0 10.0 10.0 Total Heat Input (MMBtu/hr) 22.95 22.75 27.75

CH 4 Results

Concentration (ppmvd) 1.3 1.3 1. 4

Mass Emission (lb/hr) 0.043 0.031 0.039

Production Based Emission (kg /MMBtu) 0.00084 0.00063 0.00063

Table A48 Run Data for Source ACCB1

Test Parameters

Date 7/29/2009 7/29/2009 7/30/2009

Stack Flow Rate (dscfm) 140489 141268 1385 79

Run Number

Bark (%) 100.0 100.0 100.0 Total Heat Input (MMBtu/hr) 685.26 655.20 655.82

CH 4 Results

Concentration (ppmvd) 4.12 0.58 1.82

Mass Emission (lb/hr) 1.45 0.21 0.63

Production Based Emission (kg /MMBtu) 0.00096 0.00014 0.00043B1



### APPENDIX B

PRINCIPLES OF FTIR ANALYSIS

Fourier transform infrared (FTIR) spectroscopy is a type of spectral analysis that pairs the fundamentals of infrared analysis with fast Fourier transform mathematics to achieve quick and reliable multi-gas analysis. The following is a basic explanation of FTIR analysis and technology
(Smith 1996).

1.0 INFRARED ANALYSIS

A wavelength is the distance, usually measured in centimeters, between adjacent light wave peaks. The reciprocal of that wavelength is referred to as a wave number (cm -1 ). Within the electromagnetic spectrum, wave numbers between 4,000 and 400 cm -1 are referred to as the mid-infrared range. It is within this range of wave numbers that most FTIR spectrometers operate.

Most chemical compounds absorb infrared radiation, with the exception being diatomic homogeneous molecules (N 2 , H 2 , O 2 , etc.). Chemical bonds absorb infrared energy causing the bonds to vibrate or rotate. Depending on the type of chemical bond and its placement within the molecule, specific wavelengths will be absorbed. The overall transmittance of the wavelengths ’ intensity decreases as the wavelengths are absorbed by compounds. Plotting wave numbers versus transmittance results in a sample spectrum. Spectra also can be based on absorption, determined by the following equation.

A = log (1/T)

where A is absorption and T is percent transmittance. The number and placement of absorption peaks across the mid-IR range is unique and constant for every compound and can be considered a physical property of that compound. This allows for qualitative analysis of samples with IR spectroscopy.

Based on Beer ’ s law, which states that concentration and absorbance are directly proportional, IR spectroscopy may be used for quantitative analysis as well. Beer ’ s law is summarized as

A = lc

where A is absorption measured in peak height, is the absorptivity constant for a particular compound, l is the path length of the analyzer ’ s sample cell, and c is the concentration of the compound. Since absorptivity is a constant for each compound, it can be seen that when the path length remains fixed, as concentrations increase so will the absorption peaks. This allows for the quantitative analysis over a wide range of concentrations.

2.0 FTIR COMPONENTS

All FTIR analyzers contain the same basic setup in terms of hardware. The five most critical components are the infrared source, interferometer, sample cell, detector, and signal/data processors (Figure B1).B2

Figure B1 FTIR Components

IR Source : The purpose of the IR source is to produce light waves throughout the infrared range. Infrared radiation is sometimes referred to as heat radiation; therefore, the IR source is simply a heated element. For example, a ceramic element heated by passing electricity through it could be used

as an IR source.

Interferometer : The interferometer is an important and unique part of FTIR analyzers, and it is what makes IR analysis over a wide spectral range possible. The most commonly used are Michelson interferometers which consist of a beam splitter, a fixed mirror, and a moving mirror (Figure B2).

Figure B2 Interferometer IR Radiation

Beamsplitter Fixed

Mirror Moving

Mirror Sample

Cell Interferometer

Detector IR Source

Sample

Processor

Sample

In Sample

Out

Data

Cable to ComputerB3

As infrared radiation from the source enters the interferometer, it encounters a beam splitter that

allows half of the IR beam to continue forward while the other half is reflected. One half of the beam will go to a fixed mirror, and the other half travels to a moving mirror. The radiation is then reflected off the mirrors and recombines at the beam splitter, where it then exits the interferometer. The purpose of the interferometer is to make two beams of light travel different distances. When the moving mirror and fixed mirror are the same length from the beam splitter, the divided light waves will have traveled the same distance when they recombine. The wave amplitudes will be in phase. The waves will constructively interfere with each other, and the resulting wave leaving the interferometer will have an amplitude greater than the one that entered. As the moving mirror changes positions, the optical path length toward the moving mirror changes and wavelengths will go out of phase with each other. When they are completely out of phase, peaks and valleys cancel each other out and destructive interference occurs. The mirror continues until it reaches the maximum optical path difference and then returns to its original position, completing one scan.

Sample Cell : The sample cell is a compartment that allows for the interaction of the gaseous sample with the infrared radiation. The compounds within the gas stream will absorb the radiation at this time. For continuous analyzers, the sample gas stream flows through the cell at a constant rate. With batch analyzers, the sample is introduced into the cell, sealed off, and analyzed. The cell is evacuated before the next sample is introduced. The distance that the IR beam travels through the sample cell is the path length. Some analyzers allow for adjustment of the path length while others are fixed.

Detector : The modified IR beam travels from the interferometer, through the sample gas stream, and finally to the detector. The detector measures the infrared intensity of the incoming beam and converts it into an electrical signal. Within the interferometer, as the light waves move in and out of phase, the resulting combined light wave will increase and decrease in intensity. The output from the detector results in a plot of IR intensity, measured in voltage, versus optical path difference. This is known as an interferogram.

Sample Processor : Before the interferogram is quantified, adjustments to the spectrum are performed to maximize analysis. The spectrum is converted from analog to digital, corrected for symmetry, and peak intensities are adjusted.

3.0 SPECTRAL ANALYSIS

The final interferogram is sent to the analyzer software, where it is transformed. A complex algorithm known as a fast Fourier transform is applied to the interferogram and converts it from intensity vs. optical path difference to absorption vs. wave number.

The first step in analysis is to obtain a background spectrum, which is the detector ’ s response with no sample in the sample cell. This can be accomplished by continuously passing nitrogen though the cell. IR absorption at all wavelengths goes to zero.

3.1 Single Component Analysis

A sample gas stream enters the cell as IR radiation is passed through it. The radiation is absorbed at certain wavelengths depending on the compound present. The detector ’ s response to the sample is ratioed against the background response and the result is a spectrum of absorption peaks that are attributed to the sample.

Reference spectra for the compound of interest are required for analysis. These are obtained by passing the single compound through the sample cell at a known concentration and storing the spectral results. A range of reference spectra should be produced to include all concentrations that the sample may fall within. Absorptivity is calculated from these reference spectra. The absorptivity,B4

absorption peak height, and path length are now known. Referring back to Beer ’ s law, the software can now quantify the concentration of the unknown sample.

3.2 Multiple Component Analysis

The calculations are more involved for analysis of two or more components. The calculation to determine the single component concentration is still used; however, a separate calculation must be performed for every additional compound present in the gas stream. The situation is complicated even more by the fact that two compounds can have absorption peaks in or around the same wave number. The absorption due to each compound must be determined within this wave number. Using matrix algebra allows for the fast computation of multiple compound concentrations over a wide wave number range. One requirement when using this method is that all compounds within the sample stream must be accounted for in the analysis. Absorption peaks from any compound not present in the analysis will interfere with the accurate quantification of the other compounds. These peaks that are unaccounted for after analysis are referred to as residual peaks. Interfering residuals can be removed by including the compound responsible for these peaks in the analysis. It is important to have a large reference library with all compounds that may be present when testing unknown sample streams.

Another cause of interference can arise from large concentrations of compounds absorbing near the target analytes. Large absorption peaks can dominate a wave number and, in extreme cases, can cause complete saturation of the wave number in which the maximum amount of radiation at that wavelength is being absorbed. If this occurs at or around the analysis area of the target analytes, it can make analysis difficult or even impossible in that area. Proper selection of the analysis area is important for this reason.

REFERENCE

Smith, B.C. 1996. Fundamentals of Fourier transform infrared spectroscopy . Boca Raton, FL: CRC

Press.C1



### APPENDIX C

METHOD DEVELOPMENT

1.0 INTRODUCTION

The two main methods for extractive FTIR analysis are EPA Method 320 and ASTM Method D 6348-03. Both methods require a sampling setup that includes a filter, sample lines, sample pump, and analyzer, with all components heated to avoid condensation. An equipment setup similar to the one illustrated in Figure C1 is recommended.

Figure C1 FTIR Sampling System

Due to the nature of FTIR spectroscopy, poorly quantified peaks absorbing in the same analysis area as the target analytes are known as interferences. These interferences can compromise the accurate quantification of the target analytes. Initial testing of biomass boilers revealed large concentrations of water and carbon dioxide, with relatively low concentrations of CH 4 and N 2 O. The testing showed that water peaks were interfering with CH 4 analysis and increasing detection limit levels. Carbon

dioxide was found to interfere with N 2 O analysis; however, it was found that careful selection of N 2 O analysis areas could avoid this problem.

The EPA and ASTM methods allow for a sample conditioning system to be placed in-line to reduce interfering compound concentrations to an acceptable level. A condenser was proposed to reduce the moisture content of the gas stream before it enters the sample system. The condenser consisted of a chilled, empty Rotavis® impinger in front of the particulate filter. The modified setup was tested at a LaptopAnalyte SpikeCTS Spike Mass Flow

ControllerUHP Nitrogen Pneumatic

O 2

Heated Sample

Pump Heated

Line Heated Filter SS

Probe

FTIR

Vent Heated

LineC2

recovery furnace. Modified and standard setups were alternated for a total of five runs each. The results were used to evaluate the ability of the modified system to improve CH 4 analysis.

The results seen in Table C1 show a dramatic reduction in sample moisture content. The CH 4 detection limits were lowered by 1.5 ppm as a result. The recovery furnace tested contained low

concentrations of CH 4 , and this reduction in detection limit dramatically improved analysis.

Table C1 Standard and Modified Setup

Setup Moisture Content
(%) Methane DL (ppm)

Standard 26.22 2.45

Modified 0.82 0.93

The reduction in moisture could allow collection of source samples in Tedlar® bags for later analysis. This would be beneficial when direct sampling at a source is not practical.

A laboratory study was performed to fully evaluate the sample conditioning system before it was incorporated into the equipment setup. The study was divided into three phases. The first phase determined which conditioning techniques were most efficient at removing moisture from the gas stream, while not affecting the N 2 O and CH 4 concentrations. Phase 2 examined sample stability over time. Phase 3 of the study insured that analyte spiking could be accomplished from the Tedlar® bag. A gas manifold was constructed to create a synthetic boiler gas stream. N 2 , N 2 O, CH 4 , NO, SO 2 , and

O 2 from gas cylinders were combined with steam from a steam generator to produce the synthetic gas

matrix.

2.0 METHOD

2.1 Phase 1

Phase 1 evaluated methods for removal of water while preserving N 2 O and CH 4 concentrations. The three conditioning systems evaluated were

1. a chilled, empty Rotavis® impinger with a shorted stem to prevent bubbling of the sample gas through the collected water;

2. a chilled impinger followed by a Nafion® dryer; and

3. a chilled impinger followed by an impinger filled with silica gel.

A dry mixture of gases was sent directly to the analyzer to determine CH 4 and N 2 O concentrations. The gas stream was then sent through each of the three conditioning systems before going to the analyzer to determine if there was an effect on CH 4 and N 2 O concentrations. Water vapor was added to the gas stream to bring the moisture content up to 30%. The wet gas stream was then sent through each of the three conditioning systems before going to the analyzer.C3

2.2 Phase 2

In Phase 2, gas samples were collected in Tedlar® bags after they passed through the most appropriate conditioning system determined in Phase 1. Samples were analyzed immediately after collection and then every hour for four hours to evaluate short-term stability. The bags were analyzed again after 48 and 72 hours to evaluate long-term stability.

2.3 Phase 3

Phase 3 was designed to ensure that dynamic spiking could be accomplished from the Tedlar® bags for quality assurance, as required by the FTIR methods. Two bags were filled with dry mixtures of gases that would result in CH 4 and N 2 O concentrations of 6 ppm in the first bag and 2 ppm in the second. Bags were analyzed to determine the CH 4 and N 2 O concentrations. Analyte spiking for both compounds was performed as it would be in the field, and the percent spike recovery was determined.

3.0 RESULTS

3.1 Phase 1

There was no analyte reactivity through the condenser impinger alone; however, there was a slight negative bias for CH 4 and N 2 O when the Nafion® dryer or silica gel was added. The bias for N 2 O was the same for both Nafion® dryer and silica gel, while the Nafion® dryer exhibited higher reactivity

for CH 4 than the silica gel. The percent differences in all cases was considered minor and within an acceptable range. Table C2 summarizes the results of the dry gas tests.

Table C2 Phase 1 Results (dry gas stream)

Concentration (ppmvd)

Component FTIR Direct Analysis Impingers Only Impingers + Nafion® Dryer Impingers

+ Silica Gel

H 2 O 0 0 0 0

N 2 O 6.6 6.6 6.5 6.5

NO 59 59 59 51

CH 4 7.8 7.8 7.6 7.7

SO 2 268 268 268

- 1.4

O 2 13.9 13.9 13.8 13.4

N 2 O Bias 0%

- 1.5%

- 1.5%

CH 4 Bias 0%

- 2.6%

- 1.3%

All three setups were efficient at reducing the moisture content from 30% to an acceptable level. The impinger plus silica gel configuration was the most effective as it was able to remove all moisture from the gas stream. Reactivity of the target analytes was again measured with the wet gas stream. The impinger and impinger/Nafion® dryer setups showed no bias for N 2 O, while the impinger/silica gel showed a slight positive bias. All three configurations showed a negative bias for CH 4 with the impinger/Nafion® dryer being the most pronounced. Table C3 summarizes the results of the moist

gas tests.C4

Table C3 Phase 1 Results (moist gas stream)

Concentration (ppmvd)

Component Dry Gas

FTIR Direct Impingers Only Impingers + Nafion® Dryer Impingers

+ Silica Gel

H 2 O 0 0.7 0.4 0

N 2 O 6.6 6.6 6.6 6.8

NO 59 59 58 47.3

CH 4 7.6 7.3 7.0 7.1

SO 2 270 245 247 0

O 2 13.7 13.7 13.8 13.4

N 2 O Bias 0% 0% 3.0%

CH 4 Bias

- 4.0%

- 8.0%

- 6.6%

3.2 Phase 2

A literature review was performed to investigate storage and stability of CH 4 and N 2 O from combustion sources. An article written by Muzio et al. (1989) revealed that storing combustion gases containing SO 2 , NO, and H 2 O, even over a short period of time, can lead to the formation of N 2 O within the vessel. A study by Preto et al. (2004) investigated the mechanism for this formation and

concluded that SO 2 , NO, H 2 O, and O 2 can all play a role, with SO 2 being a major factor. This effect was seen in the lab study when bag samples were collected and stored with only the condenser impinger used. Water was reduced but not eliminated, and NO, SO 2 , and O 2 concentrations were unaffected. There were slight increases in N 2 O and CH 4 over a four-hour period. Over a two-day period, there was no significant change in CH 4 while N 2 O increased by 58%. Table C4 summarizes the results. Figure C2 illustrates the changes of N 2 O and CH 4 over the 48-hour time period.

It was discovered during this test that the Tedlar® bags are porous with respect to water vapor. The percent moisture, while starting out low, increased over time approaching ambient moisture content.

Table C4 Sample Stability (no dryer)

Time (hours) 0 2 4 48

Component Concentrati on (ppmvd)

H 2 O 0.8 1.1 1.4 1.7

N 2 O 7.1 7.1 7.2 11.2

NO 48.8 20.5 13.0 6.1

NO 2 9.8 53.6 36.7 23.4

CH 4 7.3 8.1 8.2 7.2

SO 2 247.0 247.1 245.5 198.0

O 2 13.7 13.7 13.7 13.1C5

Figure C2 Stability over Time (no dryer)

During the first phase of the study, it was noted that the impinger/silica gel combination not only eliminated all water vapor, but it also had the ability to scrub out SO 2 from the gas stream. The

removal of H 2 O and SO 2 would greatly enhance the stability of N 2 O concentrations in the Tedlar® bags. Therefore, it was determined that a chilled impinger followed by a silica gel impinger was the most appropriate sample conditioning setup.

While the silica gel is efficient at scrubbing SO 2 from the gas stream, during long runs the silica gel

can become saturated and SO 2 will break through. This explains the presence of SO 2 in the stability study bag, even though the impinger/silica gel combination was used. Over a four-hour period, CH 4 and N 2 O concentrations remained stable, with only slight fluctuations from sample to sample. Over a 48- and 72-hour period, CH 4 concentrations decreased slightly and N 2 O concentrations increased. The

increase in N 2 O can be explained by the small presence of SO 2 in the samples. Table C5 summarizes the stability study results. Figure C3 illustrates the change in N 2 O and CH 4 concentrations over time.

Table C5 Sample Stability (silica gel dryer)

Time (hrs) 0 0.5 1 2 3 4 48 72

Component Concentration (ppmvd)

H 2 O 0 0.3 0.3 0.5 0.7 0.8 0.7 0.8

N 2 O 7.5 7.6 7.5 7.5 7.6 7.6 7.9 8.1

NO 53 30.1 25.5 19.0 13.9 12.5 1.1 0.5

NO 2 0 23.9 31.5 42.0 47.9 50.8 44.1 38.6

CH 4 8.1 7.9 7.9 8.1 8.0 7.9 7.8 7.7

SO 2 69 72.6 71.9 73.1 72.1 72.6 62.6 61.2

O 2 13.8 14.3 13.3 13.9 14.7 13.9 12.6 1 2.3 0.00 2.00 4.00 6.00 8.00 10.00 12.00

0 2 4 48ppmvd

Hours N2O

CH4C6

Figure C3 Stability over Time (silica gel dryer)

3.3 Phase 3

For both CH 4 and N 2 O

, the spike recovery from bag one was 101%. The percent spike recoveries from bag two were 97% for CH 4 and 96% for N 2 O. All spike recoveries were well within acceptable ranges. Table C6 summarizes the spike recovery data.

Table C6 Phase 3 Results

Concentration (ppmvd)

Component Unspiked Desired Spike Level Expected

Concentration Spiked

Concentration Percent Recovery Bag One

N 2 O 6.4 6.0 12.0 12.1 101

CH 4 6.7 5.5 11.5 11.6 101 Bag Two

N 2 O 2.2 2.0 4.2 4.0 96

CH 4 2.7 3.0 5.5 5.4 97 0 1 2 3 4 5 6 7 8 9 10

0 0.5 1 2 3 4 48 72ppm

Hours 

## Covered

N2O

CH4C7

4.0 CONCLUSION

The results from the lab study show that a chilled impinger followed by a silica gel impinger is an appropriate conditioning system for reducing water vapor and SO 2 concentrations within a gas stream. The system was also shown to have little to no effect on CH 4 and N 2 O concentrations. The experiment demonstrated the stability of a bag sample up to four hours and possibly longer if conditioned properly. Sample run times should be limited to avoid SO 2 breakthrough. The ability to carry out accurate spiking while sampling from the Tedlar® bags was proven.

REFERENCES

Muzio, L.J., Teague, M.E., Kramlich, J.C., Cole, J.A., McCarthy, J.M., and Lyon, R.K. 1989. Errors in grab sample measurements of N 2 O from combustion sources. Journal of the Air Pollution

Control Association 39:287-293.

Preto, F., Wang, J., Jia, L., and Anthony, E.J. 2004. A study on mechanisms of nitrous oxide formation in post-combustion flue Gases

. Atmospheric Environment 38:1123-1131. http://dx.doi.org/10.1016/j.atmosenv.2003.11.021

### APPENDIX B

# ncasi

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT, INC. P.O. Box 13318, Research Triangle Park, NC 27709-3318 Phone (919) 941-6400 || Fax (919) 941-6401

Vipin K. Varma, PhD Vice President – Air Quality vvarma@ncasi.org

November 8, 2012



### Mr. Paul Noe Vice President, Public Policy American Forest and Paper Association
1111 19th Street, NW

Suite 800 Washington, D.C. 20036

Dear Mr. Noe,

This is a follow-up to the earlier NCASI communication, dated September 20, 2012, notifying you of the availability of NCASI Technical Bulletin No. 998, Methane and Nitrous Oxide Emissions from Biomass-Fired Boilers and Recovery Furnaces . This Technical Bulletin, released on September 18, 2012, compiles data from an NCASI study to quantify methane (CH 4 

### ) and nitrous oxide (N 2 

### O) emissions from biomass-fired boilers and kraft recovery furnaces.

The above-mentioned study generated additional data on CH 4 

### and N 2 

### O emissions associated with the burning of kraft pulping liquors in recovery furnaces. Five direct contact evaporator (DCE) recovery furnaces and three non-direct contact evaporator (NDCE) recovery furnaces were tested during the study. Given that multiple DCE and NDCE units were tested during the study, the Technical Bulletin maintained DCE and NDCE furnaces as distinct categories and developed unique CH 4 

### and N 2 

### O emission factors for these categories.

As discussed in Section 5.3 of NCASI Technical Bulletin No. 998, the CH 4 

### and N 2 

### O emission factors compiled by the Intergovernmental Panel on Climate Change (IPCC) and the World Research Institute and The World Business Council for Sustainable Development (WRI/WBCSD) do not distinguish between DCE and NDCE recovery furnaces. Additionally, in Table AA-1 to Subpart AA in the Greenhouse Gas Reporting Rule (GHGRR), EPA mandates the use of a single emission factor (0.030 kg/MMBtu for CH 4 

### and 0.005 kg/MMBtu for N 2 

### O) for kraft pulping liquors without distinguishing between DCE and NDCE furnaces. When the data for DCE and NDCE furnaces from the NCASI study are grouped into a single category, average CH 4 

### and N 2 

### O emissions for recovery furnaces are 0.0019 and 0.00042 kg/MMBtu, respectively, as summarized in the Table below (modified from Tables 5.2 and 5.3 of the Technical Bulletin with DCE and NDCE furnaces combined into a single category).CH 4 and N 2 O Emission Factors for Kraft Pulping Liquors, kg/MMBtu

GHG IPCC WRI/WBCSD

GHG Protocol EPA 1 NCASI Study
Mean (%RSD) NCASI Study Range

Methane
(CH 4 ) 0.0030 0.0025 0.030 0.0019 (190%) 0.000042 – 0.010

Nitrous Oxide
(N 2 O) 0.0020 0.0020 0.0050 0.00042 (68%) 0.00015 – 0.00082

1 Emission factors mandated for use in GHG Inventories



### Please do not hesitate to contact me at 352- 331-1745 (ext. 260) or vvarma@ncasi.org , if you have additional questions on this topic or on the NCASI Technical Bulletin.

Sincerely,

Vipin Varma

cc:

Derek Sain, Senior Research Associate, NCASI Brad Upton, Principal Research Engineer, NCASI Reid Miner, Vice President, Sustainable Manufacturing, NCASI

# ncasi

NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT, INC. P.O. Box 13318, Research Triangle Park, NC 27709-3318 Phone (919) 941-6400 || Fax (919) 941-6401

Vipin K. Varma, PhD Vice President – Air Quality vvarma@ncasi.org

November 8, 2012



### Mr. Robert Glowinski

President and CEO

American Wood Council 803 Sycolin Road

Suite 201 Leesburg, VA 20175

Dear Mr. Glowinski,

This is a follow-up to the earlier NCASI communication, dated September 20, 2012, notifying you of the availability of NCASI Technical Bulletin No. 998, Methane and Nitrous Oxide Emissions from Biomass-Fired Boilers and Recovery Furnaces . This Technical Bulletin, released on September 18, 2012, compiles data from an NCASI study to quantify methane (CH 4 

### ) and nitrous oxide (N 2 

### O) emissions from biomass-fired boilers and kraft recovery furnaces.

The above-mentioned study generated additional data on CH 4 

### and N 2 

### O emissions associated with the burning of kraft pulping liquors in recovery furnaces. Five direct contact evaporator (DCE) recovery furnaces and three non-direct contact evaporator (NDCE) recovery furnaces were tested during the study. Given that multiple DCE and NDCE units were tested during the study, the Technical Bulletin maintained DCE and NDCE furnaces as distinct categories and developed unique CH 4 

### and N 2 

### O emission factors for these categories.

As discussed in Section 5.3 of NCASI Technical Bulletin No. 998, the CH 4 

### and N 2 

### O emission factors compiled by the Intergovernmental Panel on Climate Change (IPCC) and the World Research Institute and The World Business Council for Sustainable Development (WRI/WBCSD) do not distinguish between DCE and NDCE recovery furnaces. Additionally, in Table AA-1 to Subpart AA in the Greenhouse Gas Reporting Rule (GHGRR), EPA mandates the use of a single emission factor (0.030 kg/MMBtu for CH 4 

### and 0.005 kg/MMBtu for N 2 

### O) for kraft pulping liquors without distinguishing between DCE and NDCE furnaces. When the data for DCE and NDCE furnaces from the NCASI study are grouped into a single category, average CH 4 

### and N 2 

### O emissions for recovery furnaces are 0.0019 and 0.00042 kg/MMBtu, respectively, as summarized in the Table below (modified from Tables 5.2 and 5.3 of the Technical Bulletin with DCE and NDCE furnaces combined into a single category).CH 4 and N 2 O Emission Factors for Kraft Pulping Liquors, kg/MMBtu

GHG IPCC WRI/WBCSD

GHG Protocol EPA 1 NCASI Study
Mean (%RSD) NCASI Study Range

Methane
(CH 4 ) 0.0030 0.0025 0.030 0.0019 (190%) 0.000042 – 0.010

Nitrous Oxide
(N 2 O) 0.0020 0.0020 0.0050 0.00042 (68%) 0.00015 – 0.00082

1 Emission factors mandated for use in GHG Inventories



### Please do not hesitate to contact me at 352- 331-1745 (ext. 260) or vvarma@ncasi.org , if you have additional questions on this topic or on the NCASI Technical Bulletin.

Sincerely,

Vipin Varma

cc:

Derek Sain, Senior Research Associate, NCASI Brad Upton, Principal Research Engineer, NCASI Reid Miner, Vice President, Sustainable Manufacturing, NCASI

### APPENDIX C

### From: Hogan.Sean@epamail.epa.gov [mailto: Hogan.Sean@epamail.epa.gov ]

Sent: Thursday, June 16, 2011 4:43 PM

To: Hale, Rhea

Cc: Jacobson.David@epamail.epa.gov ; Hanle.Lisa@epamail.epa.gov ; Tunnessen.Walt@epamail.epa.gov Subject: Re: MMR question regarding Black Liquor emission factor

Hi Rhea -

In response to your question, a range of emission factors for recovery furnaces combusting black liquor is provided in Appendix F (see App F, Table 8) of the WRI/WBCSD GHG Calculation Tool for Pulp and Paper Mill s (developed by NCASI/ICFPA for WRI/WBCSD).
Given the limited data, the emission fact ors in Subpart AA, Table AA-1, were derived conservatively based on the maximum of the ra nges provided in Appendix F, Table 8 (30 kg CH4/TJ and 5 kg N2O/TJ). When converted to CO2e and summed, this totals 2.2 kg/GJ. The 0.67 kg/GJ indicated by AF&PA in their August 2009 supplemental comments is based on the median values in Appendix F, Table 8 (2.5 kg CH4/TJ and 2 kg N2O/TJ).

- Sean

Sean P. Hogan Program Integration Branch Climate Change Division EPA Office of Atmospheric Programs
(202) 343-9233 hogan.sean@epa.gov

NOTICE: Any communication on the mandatory GHG reporting rule is intended to provide general and administrative information about the Rule. This communication does not provide legal advice, and responses to questi ons received do not have legally binding effect or expressly or implicitly create, expand, or limit any legal rights, obligations, responsibilities, expectations, or benefits in regard to a ny person. Facility owners or operators and suppliers are responsible for de termining how they would be affected by the requirements of the Rule.

From: "Hale, Rhea" < Rhea_Hale@afandpa.org >

To: Sean Hogan/DC/USEPA/US@EPA

Date: 06/10/2011 04:56 PM Subject: MMR question regarding Black Liquor emission factor

### Sean,

In AF&PA’s original comments on the reporting rule we noted that the CH4 and N2O factors for black liquor are quite a bit hi gher than what is typically used in the industry. For example

factor for CH 4 

### and N 2 

### O emissions for spent pulping liquor from the WRI/WBCSD GHG Calculation Tool for Pulp and Paper Mill s – developed by NCASI/ ICFPA for WRI/WBCSD – (expressed as CO 2 

### equivalents) is .67 kg/GJ, the EPA factor is three tim es greater at 2.2 kg/GJ. Because many of our mills combust a large amount of black liquor, this difference in

the factor can add tens of thousands of CO2e to our emissions totals for a single company. To our knowledge, we did not receive an EPA response on this issue when the rule came out and wondered if EPA could clarify for us where the EPA factors come from. As our mills

continue to work on their GHG data collection, this issue has come up.

Here’s what AF&PA submitted (on August 10, 2009) as a comment to EPA on the draft rule: “EPA should provide background reference mate rial regarding how factors in Table AA-1 were developed. The values for biogenic CO 2 

### in Table AA-1 are very close to, but not equivalent to, those provided in the WRI/WB CSD GHG Protocol Calculation Tools for the pulp and paper sector. The CH 4 

### and N 2 

### O factors provided in Ta ble AA-1 are quite a bit higher than those in th e WRI/WBCSD Tools.”

Thanks for any help you can provide and I look forward to seeing you in Memphis next

week.

Best regards,

Rhea

Rhea Hale Director, Climate & Air Programs

AMERICAN FOREST & PAPER ASSOCIATION 1111 19th Street, NW, Suite 800, Washington, D.C. 20036 Rhea_Hale@afandpa.org

202-463- 2709 (phone) 202-463-2772 (fax) www.afandpa.org