MISSION TESTING STANDARD 

FOR 

WOOD FUEL BOILERS 

PRESENTED BY THE WASHINGTON-OREGON 1973 HOG FUEL BOILER STUDY 

COMMITTEE 

CHAIRMAN: H. H. BURKITT, CHIEF ENGR. SERVICES 

OREGON DEPARTMENT OF ENVIRONMENTAL QUALITY 

1234 S. W. MORRISON STREET 

PORTLAND, OREGON 97205 

NOVEMBER 28, 1973 

D.O.E. SOURCE TEST METHOD 101
ACKNOWLEDGEMENT 

The voluntary contributions of all who have served on the Oregon-Washington Hog Fuel 

Boiler Committee through meeting discussion and comments is acknowledged. 

Acknowledged in particular is the work of the standard drafting task group consisting 

of: 

George S. Beckwith, 

Chairman 

Oliver A. Fick 

Wesley D. Snowden 

David Junge 

John F. Kowalczk 

Washington-Oregon Hog Fuel Boiler Committee Attendance: 

Dave Junge 

R. W.Boubel 

Gene Wellman 

Wes Snowden 

Oliver Fick 

Rick Reid 

Paul Johansen 

Chuck Clinton 

Rod Schmall 

Jim Walther 

Rick Kester 

LaMont Matthews 

Wallace Cory 

H. H. Burkitt 

John F: Kowalczk 

Bill Prastka 

OSU 

OSU 

Oregon Tech. 

Valentine, Fisher & Tomlinson 

IPCO 

CH2M-Hill 

ODEQ 

ODEQ 

NCASI 

Crown Zellerbach 

PSAPCA 

CH2M-Hill 

Boise Cascade 

ODEQ 

ODEQ 

SWAPCA
TABLE OF CONTENTS 

TITLE: EMISSION TESTING STANDARD FOR WOOD FUEL BOILERS 

1.0 Introduction Page 

1.1 Purpose 1 

1.2 Applicability l 

2.0 General Instructions 3 

2.1 A. Operating and testing conditions required or test. 3 

2.2 B. Boiler identification and test related basic data to be recorded. 4 

3.0 Stack Gas Moisture, 02 -CO2 -CO Measurement Methods 5 

3.1 A. Moisture 5 

3.2 B. Analysis for 02 –C02 –C0 6 

4.0 Stack Gas Flow Measurement 9 

5.0 Particulate Sampling Points - Number required and location 10 

6.0 Particulate Sampling and Analysis 13 

7.0 Source Test Report Outline 17 

8.0 Source Test Data Forms 18 

8.1 Basic Source Data 18 

8.2 Orsat Analysis Data 21 

8.3 Velocity Data and Calculation 22 

8.4 Source Sampling Field Data 23 

8.5 Laboratory Report 24 

8.6 Particulate Concentration and Emission Calculation 25 

9.0 References 26 

10.0 Appendix 27 

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WOOD FUEL BOILER 

1.0 INTRODUCTION 

1.1 PURPOSE 

 This standard provides the referee method for the sampling of particulate air 

pollutant emissions from wood fuel (hog fuel) boilers. 

 Use of test method adaptations, adjustments and short cuts found acceptable to 

all parties in advance of testing is not precluded. The standard method shall be 

the basis for validating all alternate methods. 

 The inclusion of requirements for the visual determination of plume opacity is 

anticipated in areas where such a requirement exists and in these instances 

plume opacity measurements shall be accomplished in accordance with EPA 

Method 9 (Ref.). Requirements for measurement of additional pollutants are 

not excluded and may be made by local authority. Such measurements shall be 

made in the manner so required. 

1.2 APPLICABILITY 

 This standard specifies in detail the test methods for the sampling and 

evaluation of wood fuel boiler particulate air pollutant emissions. The tested 

wood fuel boiler, a furnace and indirect heat exchanger, shall be operated at the 

maximum expected steam production rate, as established by the owner, and the 

furnace shall be burning the principle fuel during the emission test. Auxiliary 

fuels, if normally used, may be used during the test if found by advance 

agreement to be acceptable. 

 The results obtained by this sampling and analysis method are the acceptable 

measures of the maximum particulate emission from the furnace. 

 This standard applies to single boilers and to multiple boiler combinations, 

where short manifolded breechings do not permit individual boiler sampling. 

2.0 GENERAL INSTRUCTIONS 

2.1 OPERATIONS AND TESTING CONDITIONS REQUIRED 

2.1.1 In recognition of the substantial variations in both the installation and operation 

of wood fuel fired boilers, the regulations pertaining to boiler operation during 

compliance testing and the standard test procedure used to determine if a boiler 

is operating in compliance are both subject to negotiation and modification. It 

is recommended that all __________________ compliance with emission 
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standards be discussed in detail ____________ regulatory agency prior to the 

actual test and must be agreed to in writing by the person responsible for the test 

and the regulatory agency. 

2.1.2 Each test run shall be carried out with the boiler producing steam at a rate equal 

to the average normal maximum steam production rate of the boiler. Following 

successful completion of the test demonstrating that the boiler was operated 

within the emission limitations as established by _________________, the 

boiler may be certified for operation at a steam production rate up to but not to 

exceed the steam production rate at which the test was carried out. 

2.1.3. For those installations in which more than one boiler is ducted to a common 

exhaust stack, the owner/operator has the option of demonstrating compliance 

for each individual boiler, or demonstrating compliance for the combined 

exhaust gas flow through the stack subject to the following limitations: 

2.1.3.1 If the boilers ducted to a common stack are not subject to the same emission 

limitations, then each boiler must be shown to be in compliance with the 

regulations applicable to it. 

2.1.3.2 If the boilers ducted to a common stack are not subject to the same emission 

limitations, compliance with the emission regulations may be demonstrated if 

the test results of the combined exhaust gases are within the most restrictive 

limitation applied to any of the boilers. 

2.1.3.2 As noted above, certification for operation of each boiler ducted to a common 

exhaust stack will be based upon the steam production rate for each boiler at 

which the certification test was carried out. No boiler may operate in excess of 

that steam generation rate without recertification of the ability of the unit to 

operate within the applicable emission limitations. 

2.1.4 Steam production rate shall be determined by: 

2.1.4.1 A steam flow meter connected to the primary steam header leaving each 

individual boiler being tested, or: 

2.1.4.2 A water meter connected to the boiler feed water input line to each boiler being 

tested, or: 

2.1.4.3 An equivalent system for determining steam production for each individual 

boiler tested. Equivalent steam flow metering systems are subject to approval 

by the regulatory agency. 

2.1.5 If auxiliary fuel is used during normal maximum steam production from the 
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boiler, then it should be used in the same relative proporations to the wood fuel 

during compliance certification testing. The data sheets indicate the 

information which should be supplied regarding the auxiliary fuel constituents. 

2.1.6 For each boiler compliance certification test, the data sheets entitled “Source 

Identification and related Basic Information” should be filled out completely. 

2.1.7 “Source Testing shall not be conducted during grate cleaning or soot blowing 

unless these operations are performed on a continuous basis.” 

2.2 ___________________________ (missing text) Boiler Identification and 

Related Basic Information forms included under Section G of these guidelines. 

3.0 STACK GAS MOISTURE, 02, C02 AND CO MEASUREMENT 

3.1 MOISTURE CONTENT 

3.1.1 Sources not employing wet scrubbing 

3.1.1.1 Referee Methods 

 a. EPA Method 5 (1) includes an accurate and acceptable means of measuring 

stack gas moisture content. 

3.1.2 Alternate methods 

 When fuel and firing conditions can be shown to not vary significantly during 

the testing period, and with prior approval of the appropriate regulatory agency, 

the following alternate methods may be used. At least three independent 

determinations are required, preferably one immediately before and after and 

one half-way through the test run. 

 The use of any of these alternate methods will require supporting 

documentation which clearly details the justification for its use and the steps 

followed in arriving at the final answer. 

 a. Any methods of instruments capable of accurately determining wet bulb 

temperature and the dry bulb temperature may be used. The percent 

moisture may then be determined from the appropriate psychometric 

charts or tables (3) or may be calculated using Carrier’s equation (5). 

Precautions to be used in measuring wet bulb temperatures or should be 

followed (4). 

 b. Moisture content may be calculated on the basis of ultimate analysis of the 
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fuel and a measurement of the moisture content of the air being supplied for 

combustion. 

3.1.2.1 Sources employing wet scrubbing 

 In this case the moisture content shall be determined by assuming that the gas 

its saturation vapor pressure is available from tables (6), and is converted to % 

H20 by volume as follows: 

 % H20 = 

Ps

100Psv

 Psv = saturation vapor pressure at sampling point 

 Ps – absolute static pressure at same point. 

 The possibility of including entrained water precludes the use of any other 

method. 

3.2 ANALYSIS FOR 02, C02 AND CO 

3.2.1 Sources not employing wet scrubbing 

3.2.1.1 Referee method 

 a. Sample collection. This method requires the use of a plastic (Tedlar or 

Teflon) bag for collection of the sample at a constant rate during the test 

run. Two arrangements are possible. The sample may be drawn from the 

stack through a glass wool filter, desiccant, flowmeter and a flow control 

valve by means of a leak-proof, oil-free pump which discharges into the 

bag. 

 Alternatively, the pump may be connected so as to pull a vacuum in an air 

tight chamber containing the plastic bag. With the filter, desiccant, 

flowmeter and control valve arranged as before, the sample is drawn into 

the bag by means of the vacuum created by the pump. 

 The minimum sample size is one cubic foot and the rate must be adjusted 

so that sampling will occur at a constant rate during the test run. 

 b. Sample analysis. Analysis of the collected sample requires at least three 

determinations for C02, 02 and C0, using either Fyrites or an Orsat 

analyzer. Variations in any one f the readings of more than 0.5% indicate 

problems with the analytical method. 

 Also, if the relationship: 19.1 <%C02+02+1/2%C0<21.5 does not hold, 

then there was a leak in the sample collection system or a problem at the 

source, and the sample will be invalid. 
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3.2.2 Sources employing wet scrubbing at moisture saturation. 

 With prior approval of the appropriate regulatory agency, the following methods 

may be used. Evidence justifying their use and documentation detailing the 

procedure used to arrive at the final answers will be required. 

 a. Grab sample method. This method requires the use of an Orsat analyzer 

to obtain at least six determinations of C02, 02 and C0 during the test run. 

They may be taken at convenient times, but should be as evenly spaced as 

possible throughout the test run. The results are averaged, and must all 

agree with the relationship 

 19.1 <%C02+02+1/2%C0<21.5 

 Fyrites are not acceptable because they do not analyze the same sample 

for all three components and therefore no check is available. 

 b. Other methods. With prior approval and supporting documentation, any 

of a number of proven analytical instruments (7) designed to measure 02 and/or 

C02 may be used. However, since most only measure one or the other, periodic 

verification of the data using Fyrites or an Orsat analyzer will be required. 

3.2.3 Sources employing wet scrubbing 

 If analysis made downstream from the scrubber do not meet the requirement 

that 

 19.1 <%C02+02+1/2%C0<21.5 

 the problem may be due to absorption of C02 in the scrubber. If this is the case, 

analysis using one of the aforementioned methods must be made ahead of the 

scrubber. 

References vs. example (7) 

4.0 STACK GAS FLOW MEASUREMENT 

4.1 LOCATION OF MEASUREMENT: 

 Velocity measurement should be made in a straight stack or duct, with 80% of 

the available straight duct system and 20% downstream of the point of 

measurement. Velocity measurements should not be taken with less than two 

and one-half (2-1/2) diameters of straight duct existing between the point of 

measurement and the last upstream disturbance. 

4.2 NUMBER AND LOCATION OF VELOCITY TRAVERSE POINTS 

4.2.1 Number of Velocity Traverse Points shall be determined from Figure 1. 

4.2.2 In round ducts, velocity traverse points shall be located at points of equal 
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elemental areas per Table I or equivalent. 

4.2.3 In rectangular ducts, the number of velocity traverse points shall be determined 

from Figure 1, and located at the centroid of equal elemental areas. The ratio of 

length to width of elemental areas are recommended to not exceed 2 to 1. An 

equivalent round diameter for a rectangular duct may be determined by: 

 Equivalent diameter = 2 (length) (width)/(Length + width) 

4.3 EQUIPMENT 

 “P” type of calibrated “S: type pitot tubes, or prior approval equal velocity 

measurement instrument shall be used for velocity measurement. Velocity 

instruments with an accuracy measurement with +0.01” H20 are most desirable. 

4.4 VELOCITY CALCULATION 

4.4.1 Procedure: The following procedure or equivalent may be used to perform the 

calculations 

 vs = KPCP (tsxDeltaP) avg/psMs) 1/2 

 vs = Stack gas velocity, feet/sec. 

 KP = 85.48 (ft/sec.) (Lb/lb mole – o

R) 1/2 

 CP = Pitot tube coefficient, dimensionless 

 Ts = Absolute stack gas temperature, o

R 

 Delta = Velocity head of stack gas, in. water column 

 Ps = Absolute Stack Gas Pressure, in. Mercury column 

 Ms = Molecular weight of stack gas, lb/lb mole 

4.4.2 Average Velocity: 

 Calculate average stack gas velocity by summing the square roots of the 

individual products (Ts x Deltap) and divide by the number of readings to 

determine Ts x Deltap) avg for use in the preceding equation. 

4.5 STACK GAS FLOW CALCULATION: 

 Stack gas flow equals the product of the average velocity x the cross sectional 

area of the stack or duct in the traverse plane. 

5.0 PARTICULATE SAMPLING POINTS – NUMBER REQUIRED AND 

LOCATION 

5.1 NUMBER OF POINTS 

5.1.1 Particulate sampling may be conducted at, and simultaneously to, the velocity 

traverse measurements (i.e., according to minimum traverse measurements 

points per Figure 1.) 
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5.1.2 Particulate sampling may be conducted at the minimum number of sampling 

traverse points as specified in Figure 1. (Not less than 12.) 

5.2 SAMPLING PORTS: Ports should be adequately sealed to prevent velocity 

fluctuations near port openings. 

5.3 TEST RUN: A test run consists of collecting one sample at all elemental areas 

as specified in 11, A, Number of Points. 

5.4 WALL CLEARANCE: Sampling nozzle shall no be placed within 1” of inside 

wall of stack to prevent sample contamination. 

5.5 NUMBER OF TESTS RUN: Two (2) test runs shall be the minimum number to 

establish comparative compliance data. 

5.6 TERMINOLOGY 

5.6.1 TRAVERSE: A traverse consists of collective velocity data and/or samples at 

all specified points (equal elemental areas) at a cross section of a duct. The 

number of points is specified by the cognizant procedure. 

5.6.2 TEST RUN: A test run consists of a sample collected at all specified points 

(equal elemental areas) at a cross-section of a duct. The number of points is 

specified by the cognizant procedure. 
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-9- 

6.0 PARTICULATE SAMPLING AND ANALYSIS 

6.1 Principal: Method 5, contained in the Federal Register, Vol. 36, No. 247 

(December 23, 1971), with the following additions is the recommended 

particulate emission collection method for wood fired boilers: 

 a. A complete test shall consist of a minimum of two one-hour runs. A 

complete plane-traverse shall be conducted for each run. 

 b. A minimum of 20 cubic feet of sample gas shall be collected during each 

run. 

 c. The largest size nozzle practicable while still maintaining isokinetic 

condition, stated in Method 5, shall be utilized to insure collection of large 

particles. 

 d. A stainless steel probe and filter holder (316) may be substituted for glass 

probe and holder mentioned in Method 5. 

 e. Temperature of the filter holder shall be maintained as 250°F + 25 to 

prevent possible vaporization or combustion of collected material. 

 f. Use of a cyclone between the probe and filter holder is permissible to 

obtain a rough estimate of particle size distribution. 

7.0 SOURCE TEST REPORT OUTLINE 

 The report must be made to include the information in by the following outline. 

7.1 Introduction, purpose, summary of results and conclusions. 

7.2 Description of source 

7.2.1 Process material flow rates, fuel rates, etc. 

7.2.2 Source design, type, size, etc. 

7.2.3 Process material composition, fuel composition, etc. 

7.2.4 Special conditions occurring during the source test period. 

7.2.5 Yearly average process material flow rates, fuel rates, etc. 

7.3 Sampling and analytical methods 

7.3.1 Field equipment – dates of calibration 

7.3.2 File Procedures – describe deviation from standard methods, if any. 

7.3.3 Analytical methods – describe deviations from standard methods, if any. 

7.3.4 Special problems or considerations 

7.4 Sampling point description. 

7.5 Detailed results – may be in tabulated form. 
-10- 

7.5.1 Emissions in gr/scf, in gr/scf corrected to 12% C02 if a combustion source, and 

in lb/hr. 

7.5.2 Gas volume, temperature, moisture content, and stack area. 

7.5.3 Percent isokinetic sampling rate. 

7.5.4 Other results, particle size analysis, chemical analysis, or other optional data 

that may have been obtained. 

7.5.5 Duration of test. 
-11- 

8.0 BASIC SOURCE TEST 

8.1 SOURCE IDENTIFICATION TEST

 Name of Company (Owner): 

 Location of Boiler (Stack): 

 City State 

 Name of Company Contact: 

 Name of Persons Conducting Test: 

 

 

 

 Name of Regulatory Agent(s) Present to Observe Test: 

 

 

 Stack Identification (i.e., 1, 2, ... N., S., ....): 

 How many boilers are ducted to the exhaust stack? 

 Identification of each boiler ducted to the stack: 

 1. _______________ 3. _______________ 5. _______________ 

 2. _______________ 4. _______________ 6. _______________ 

 Note: A separate boiler identification form must be filled out for each boiler 

connected to the stack. 

 Sample Point Description: 

 Is the sample point in a circular _____ or rectangular _____ duct? 

 If circular, what is the diameter? __________ (inches) 

 If rectangular, what is the height? __________ (inches) 

 What is the width? _________ (inches) 

 How far downstream from the sample point is the nearest bend or other flow 

obstruction? ______________ (ft) 

 How far upstream from the sample point is the nearest bend or other flow 

obstruction? __________ (ft) 

8.1.2 BOILER IDENTIFICATION AND DESCRIPTION 

 Boiler Identification No. (i.e., 1, w, ... N., S., ....): 

 Boiler Manufacturer 

 Installation Date: _________________ Major Revision Date: 

 Nameplate Capacity of Boiler: __________ (lbs/hr) @__________ (psig) 

 or _________ (H.P.) Water Tube: ___________ Fire Tube: 
-12- 

 Other Nameplate Data: 

 

 Spreader Stoker: ___________ Dutch Oven: __________ Other: 

Indicate which of the following are installed on the boiler: 

 ___ F.D. Fan ___ Wet Scrubber 

 ___ Automatic F.D. Fan Damper Control ___ Bag House 

 ___ I.D. Fan ___ Cinder Reinjection Sys. 

 ___ Automatic I.D. Fan Damper Control ___ Sanderdust Burner Sys. 

 ___ Automatic Fuel Feed Controller Other Control Equipment 

 ___ Continuous Recording Steam Flow Meter 

 ___ Continuous Recording Opacity Monitor 

 ___ Continuous Recording Oxygen Recorder 

 ___ Multiclone Ciner Collections 

8.1.3 STEAM GENERATION RATE DATA

 The following data should be recorded for each test run: 

 Date: ____________ Run. No.: ___________ Steam Pressure (psig): 

 Average Boiler Steam Generation Rate During Test: __________ (lbs/hr) 

 Peak Boiler Steam Generation Rate During Test: _________ (lbs/hr) 

 Minimum Boiler Steam Generation Rate During Test: _________ (lbs/hr) 

 How was steam flow rate determined: 

8.1.4 ANALYSIS OF WOOD FUEL USED DURING BOILER 

CERTIFICATION TEST

 Describe the approximate percentage make-up of the hogged fuel used 

during the compliance certification test: 

Fuel Description Approximate Percent by 

Weight (Dry) 

Planer Shavings ______________%

Sanderdust ______________%

Sawdust ______________%

Bark ______________%

Hogged White Wood ______________%

Other Wood Residues ______________%

Total ______________%
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 What is the moisture content of the mixed wood fuel on a “wet” basis? 

_____________% 

 If the boiler is equipped with a cinder reinjection system, were the cinders 

being injected during the test? __________ 

8.1.5 AUXILIARY FUEL CONSTITUENTS

 What is the normally used percentage of heat input to the boiler from? 

Aux. Fuel Description Approximate Percent of 

total BTU Input 

Natural Gas ______________%

Propane ______________%

Coal ______________%

Oil: Crude ______________%

 Light ______________%

 Other ______________%

Clarifier Sludge ______________%

Other ______________%

Wood (Hogged) Fuel ______________%

Total ______________%
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Form 8.2 ORSAT ANALYSIS DATA SHEET

Source ____________________________________________ Date 

Sampling Point Location 

RUN _________ 

 C02 02 CO N2 Time 

Analysis 1 Test Conditions 

Analysis 2 

Analysis 3 

Average 

 C02 02 CO N2 Atomic Wt. 

(44) 

Atomic Wt. 

(32) 

Atomic Wt. 

(28) 

Atomic Wt. 

(28 

 

______ + ______ + ______ + ______ + = Total Atomic Wt.

RUN _________ 

 C02 02 CO N2 Time 

Analysis 1 Test Conditions 

Analysis 2 

Analysis 3 

Average 

 C02 02 CO N2

Atomic Wt. 

(44) 

Atomic Wt. 

(32 

Atomic Wt. 

(28) 

Atomic Wt. 

(28) 

 

______ + ______ + ______ + ______ + = Total Atomic Wt.
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Form 8.3 VELOCITY DATA AND CALCULATIONS

Run No. ____________________ Date ________________ 

Plant _____________________________________________ 

Sampling Location __________________________________ 

Stack Temperature 

Point No. 

Stack 

Pressure 

Ps in. Hg 

Gauge Ts °F Ts °R 

Vel. Head 

∆P in. H20 (∆P x Ts) S = ∆PxTs

 

Avg 

Ps = absolute pressure – Ps + Po = __________ in. Hg 

Ambient temperature = __________ °F 

Ambient pressure = __________ inches of Hg 

Stack Temperature 

 Dry Bulb __________ °F 

 Wet Bulb __________ °F 

Const. C = _________________
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Total 

Avg. 

PARTICULATE SOURCE _____ING FIELD DATA 

Orifice, H in H20 Dry Gas Temp tm, °F 

Clock 

Time Point No. 

Dry Gas 

Meter 

Qm, ft3

Pitot P 

“H20 Desired Actual Inlet Outlet 

Pump 

Vacuum 

“Hg 

Stack 

Temp. ts, 

°F 

F

Te

Comments: Avg. gas temp. tm ° F 

Run No. _________ Plant 

Sampling Location Date Operator Assistant 

IMPORTANT

Nozzle Dia., Dn = _______ in. Heater Box Setting ______ °F “C” Factor ______ @ ____ °F Assumed Moisture _____ Vol. % 

Ambient temp. _Bar. Pressure, Po Begin Sampling Sampling time inProbe heater settStack pressure __
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Form 8.5 LABORATORY REPORT

 Laboratory

Test Site: Brought in by ____________ Date 

Address: Received by _____________ Date 

Date ____________ No. Runs Analysis by 

Source type Date Completed 

Run 

No. Impinger #1 #2 #3 #4 

Total 

Condensate 

 Not Cond. 

 Not Cond. 

Run 

No. Filter 

Part 1 

Probe 

Part 2 

Organic 

Ext. 

Part 3 

Water 

Ext. 

Part 4 

Imps. 

Acetone 

Total Net Wt. 

in Grams 

 

Microscopic Analysis Filter # Microscopic Analysis Filter # 

Size 

Microns 

(ave.) No. 

Cumulative 

No. % 

Size 

Microns 

(ave.) No. 

Cumulative 

No. % 

 

 Date approved by 

 Date 
-18- 

Form 8.6 PARTICULATE SAMPLING CALCULATIONS

Constant Parameters

Po = Barometric pressure - _____ in. hg Plant__________ 

As = Stack area - ____________ in.2

 Sampling Location 

Dn = Nozzle diameter - __________in. Date of Test 

 PARAMETERS TO BE CALCULATED RESULTS 

Symbol Definition, Units Calculating Equation Run __ Run __ Run __ Avg. 

Ts Stack temp., °R Avg. Fr. Field Data Sheet 

Ps Stack pressure in. Hg abs. Avg. fr. Vel. Calc. sheet 

∆H Orifice pressure drop in H20 Avg. from Field Data Sheet 

∆T Total sampling time, min. Tot. fr. Field Data Sheet 

Tm Gas Meter temp., °F Avg. fr. Field Data Sheet 

S ∆PxTs Avg. fr. Vel. Calc. Sheet 

Qm Sample gas volume at meter 

conditions, ft. 3

Avg. from Field Data Sheet 

Qm – Qm – water vapor thru 

meter 

 

Qd Dry gas sample vol. at std. cond., 

scf 460

17.7(

+ = tm

Qm Qd (Po + 

13.6

∆H ) 

Vv Tot. vol. of condensed water. Total fr. Lab Data Sheet 

Qv Tot. Vol. of Condensed water 

vapor @ std. cond. Scf. 

Qv – 0.0474 Vv = Q’v 

Qv = water vapor thru meter 

 

mv % moisture in stack gas Mv = 

Qv Qd

Qv

+

100 

md Mole fraction of dry gas Md = 

Qv Qd

Qd

+

 

Md Molecular Wt. of dry gas Gas analysis 

Ms Molecular Wt. of stack gas Ms = mdMd = 18 (1-mi) 

Vs Stack velocity at stack, Fpm Vs =4350 S (

Ps Ms

1 ) 

2

1 

qs Stack flowrate at st. conditions, 

scfm 

qs = 

Ts

0.123(Vs)(As)(md )(Ps) 

I Percent Isokinetic I = 

( )( )( )( 2)( )

1032

Vs Ps md Dn t

TsQd

∆

 

W Wt. of particulate sample, gm Total from Lab Data Sheet 

Cg Total Particulate grain loading, 

gr/scf 

Cg = 

Qds

0.154W 

C’g Grain loading at 12% C02 gr/scf Cg’ = Cg x 

(% 2)

012

CO

 

Ct Total particulate emission, lb/hr Ct = .00857 (Cg) (qs) 
-19- 

9.0 REFERENCES

 1. Vol. 36, No. 247, Part 2 of the Federal Register dated Thursday, 

December 23, 1971 

 2. ASME Power Test Code #19.18 (1932) paragraphs 44-50 

 3. Zimmerman, O.T. and I. Lavine; Psychmometric Tables and Charts, 

Industrial Research Service, Inc., Dover, New Hampshire 

 4. AICHE Source Sampling Training Manual, 1972 American Institute 

of Chemical Engineers 345 E. 47th Street, New York, N.Y. 10017 

 5. The Physics of Air, American Air Filter Company, Inc. 215 Central 

Avenue, Louisville, Kentucky (1968) 

 6. Bulletin WP-50, “Methods of determination of Velocity, Volume, 

dust, and Mist Content Gases,” Western Precipitation Division, Joy 

Manufacturing Co., 1000 West 9th St., Los Angeles, CA 90015 

 7. ASME Performance Test Coce #19.10 (1968) 
-20- 

10.0 APPENDIX 

10.1 Carrier’s Equation 

 % H20 = PSV - 

tw Ps

Ps Psv td tw 100

2800 1.3

( ) (

−

− −

 tw = wet bulb temperature, °F 

 td = dry bulb temperature, °F 

 Psv = saturation vapor pressure at tw (available from tables (6), inches Hg. 

 Ps = absolute static pressure in stack, inches Hg. 

10.2 Conversion of lbs. H20/lb. dry air to % H20 by volume 

 % H20 = ( )

W

W

+

29

18

100

 W = lbs. H20/lb. dry air available from charts or tables. 

10.3 NOMENCLATURE – SAMPLING CALCULATIONS 

VARIABLES SUBSCRIPTS

A = area, in2 or ft2 d = dry gas 

C = emission concentration or wt. g = grain loading 

D = diameter, ft. or in. m = meter conditions 

I = % Isokinetic sampling n = nozzle 

M = mole fraction or % by volume o = atmospheric 

P = pressure v = Water vapor or liquid 

q = gas volume flowrate, scfm 

Q – gas volume, ft3 or scf 

S = P xT

t = temperature, °F 

T = absolute temperature, °R 

u = velocity, fpm 

V = liquid volume, ml 

W = mass or weight, gm 

∆H = orifice pressure drop, in. H20 

∆P = pitot tube differential pressure, in. H20 
-21- 
-22- 

 water is evaporated. Desiccate and dry to a constant weight. Report 

results to the nearest 0.1 mg. 

10.4.5.2 Extract organic particulate from the impinger solution with three 25 ml. 

portions of chloroform. Complete the extraction with three 25 ml. portions 

of ethyl ether. Combine the ether and chloroform extracts, transfer to a 

tared beaker and evaporate at 70 degrees F. until no solvent remains. 

Desiccate 24 hours and dry to a constant weight and report the results to 

the nearest 0.1 mg. Determine impinger water non-extractables 

(inorganics) by evaporating extracted water solution at no more than 100 

degrees C. (use of steam table is preferred). Desiccate 24 hours and dry to 

constant weight. 

10.4.5.3 Evaporate blank samples of 100 ml. acetone (at ambient temperature and 

pressure; desiccate 24 hours and dry to a constant weight) and 25 ml 

chloroform and 25 ml. ether mixture. Evaporate blank samples of 100 ml. 

distilled and deionized water used for impinger solution and train cleanup 

(at no more than 100 degrees C., steam table preferred) desiccate 24 hours 

and dry to constant weight). Then weigh and record the residues after 24 

hour desiccation. 

10.4.6 Report 

10.4..6.1 Report total weight of all collected particulate as well as the constituents 

separately as follows: 

 a. Prefilter acetone wash. 

 b. 1st filter weight gain 

 c. Extractables 

 d. Impinger water residue 

 e. Impinger train acetone wash. 

19.46.2.2 Report physical characteristics of collected particle specimen’s as follows: 

 a. Particle size (visually determined extent of particles over 

approximately 50 microns in diameter effecting local fallout. 

 b. Presence of unburned constituents. 
-23- 

 c. Other significant aspects. 
SUPPORT DOCUMENT 

for the Air Operating Permit issued to 

Kimberly-Clark Tissue Company 

(KCTC) 

2600 Federal Ave. 

Everett, Washington 

State of Washington 

DEPARTMENT OF ECOLOGY 

300 Desmond Drive 

P.O. Box 47600 

Olympia, Washington 98504-7600 

2 

Table of Contents 

Introduction ..................................................................................................................................................3 

Statement of Basis ......................................................................................................................................5 

I. Assuring Compliance With All Applicable Requirements ..............................................................5 

I.A. Descriptions and Comments on Specific Permit Conditions .........................................6 

I.B. Comments on Facility-Wide General Requirements .........................................................................10

II. Insignificant Emission Orders ....................................................................................................................................................................................10 

III. Regulatory Orders.....................................................................................................................................................................................10 
3 

INTRODUCTION 

This Operating Permit Support Document fulfills the operating permit rule "Statement of Basis" 

requirement and explains particular portions of the air operating permit for Kimberly-Clark 

Tissue Company (KCTC). This document is not part of the operating permit for KCTC. Nothing 

in this document is enforceable against the permittee, unless otherwise made enforceable by 

permit or order. 

Mill Description 

KCTC is located in Everett, Washington, and is an integrated pulp and paper manufacturing 

facility. The site produces a wide range of tissue products including paper towels, toilet paper, 

napkins. The facility operates continuously with three shifts per day. 

The pulp mill is currently producing bleached sulfite pulp. Most of this pulp is used by the paper 

mill along with purchased kraft pulp, semi-mechanical pulp, and recycled fiber to manufacture 

tissue products for both the commercial and consumer markets. 

In general, wood chips are cooked with acid in digesters to make a pulp slurry. This slurry is then 

separated into pulp and liquor fractions. The liquor is concentrated and burned as fuel in the 

plant's recovery boiler. The pulp, is bleached. The bleached pulp either is immediately used in the 

paper mill or is dried, pressed, and baled for storage. An ammonia absorption tower recovers 

sulfur dioxide. The mill's unit processes are described further below. 

Pulping Process 

Wood chips from whole logs and sawmill residuals arrive at the plant by truck, barge, and rail car. 

The chips are stockpiled onsite in piles and silos. The chips are screened and conveyed by a 

covered belt to a batch digestion process to make pulp. Digestion occurs in an ammonium-based 

sulfite process that cooks the chips in large-batch digesters by using heat and chemicals. The 

cooking process separates the wood into its primary fractions: wood fibers and lignin, the binding 

material that holds the fibers together. 

The chemicals used in the cooking acid are ammonium bisulfite and sulfurous acid. Raw 

materials used to create the cooking acid are anhydrous ammonia, molten sulfur, and water. 

Each process unit is hooded and vented to the acid plant ammonium-based absorption tower, 

which collects and recovers sulfur dioxide. The sulfur dioxide recovered from the flue gas is 

converted to ammonium bisulfite for use in the digestion process. 

After cooking, the pulp is washed to remove the cooking liquor and organic solids. The spent 

sulfite liquor is concentrated in multiple-effect evaporators to form approximately 50 percent 

solids. This concentrated liquor is then sprayed into the plant's recovery boiler where the organic 

content in the liquor is burned, producing steam to operate the digesters and evaporators. The pulp 

is sent through screens and washers before going to the bleaching process. 

Wastewater from the pulp mill is discharged to either an onsite primary treatment process for 

removal of solids, or an onsite secondary treatment process for removal of solids and oxidation of 

organic substances. The treatment process used depends on the source of the wastewater and its 

constituents. 
4 

Pulp Bleaching 

The pulp is sent to the bleach plant to brighten the pulp. Chemicals alter and remove the lignin 

compounds in the pulp that remain after washing. After each bleaching stage, the mixture is 

washed. Wastewater from the bleach plant is sent to secondary wastewater treatment system. 

Screening, Drying, and Baling 

The bleached pulp is screened and centrifuged to remove dirt and contaminants from the finished 

pulp. Rejected material is sent to primary treatment. At this point, the cleaned pulp may be used 

immediately in the paper mill, or it may be dried on the pulp drying machines and stored for later 

use and/or sale. When needed, the dried pulp is wetted in a repulper to form a slush to be sent to 

the paper mill. Some of the dried sulfite pulp is also sold to other mills. Purchased dried pulp is 

also used daily as part of paper mill recipes. 

Paper Mill 

The paper mill receives pulp from the sulfite process as well as blends of secondary fiber and 

purchased pulp. Water is added to the pulp to make about a one-half of one percent solution. Wet 

and dry strengthening agents, and optional dyes may be added. The solution is conveyed to a 

Fourdrinier wire followed by a felt press. It is then dried and "creped" on Yankee dryers. For 

some products, optional after-dryers may be used after the Yankee dryers. For paper towels and 

toilet paper, the dried material is rolled, dyes and design imprints are added, and final embossing 

and texturing may be done. The product is rewound on rolls and perforation tears may be added. 

A rotating blade then cuts the long roll into smaller ones. For napkins, the product is cut and 

folded in the finishing process. The product is wrapped and conveyed to a distribution building for 

transport. Five paper machines are used to produce the paper products. 

Paper machine and finishing waste is called broke, and is recycled to the mill. Wet and dry 

broke from the paper machines and finishing areas are placed in a beater. The broke is treated 

with hypochlorite to bleach the dyes and to aid defibering by breaking down chemicals in the 

paper. Hypochlorite is consumed by the reactions with the fiber, dyes, and additives. Excess 

chlorine is neutralized with sodium bisulfite. The slushed broke is pumped to a broke storage 

chest and reused in the process. 

Utilities 

Five boilers (No. 14, and 7 through 10) are available to supply steam for plant operations: one 

cogenerating wood-waste boiler, three dual-fuel boilers, and a recovery boiler. Boiler No. 14 is 

a woodwaste boiler ( installed in 1995) produces about 435,000 pounds of steam per hour. Boilers Nos. 7 through 9 can burn either gas or oil and operate in swing capacity to provide extra 

steam as needed. Boiler No. 10 is the sulfite recovery boiler. The recovery boiler is used to burn 

spent sulfite liquor, and is capable of producing 330,000 pounds of steam per hour. Boiler No. 

10 also burns gas as necessary. 

The woodwaste boiler burns approximately 800.000 wet tons of fuel per year. The fuel is 

provided by local sawmills and wood products companies, and consists of sawdust, bark, and 

other wood waste. In addition, KCTC burns approximately 12,000 dry tons of dewatered sludge 

per year from the primary and secondary clarifiers of the wastewater treatment plant. This 

sludge contains about 60 percent woodwaste fiber. Minor amounts of other fuels are burned, including wood pallets and other waste paper products from onsite operations. 

Emissions from boiler No. 14 are vented to a baghouse to remove particulate material. The boiler 

5 
5 

is part of a cogeneration facility that meets plant steam needs, and also generates a total of about 

325,000 megawatt-hours of electrical power per year. This is enough power to supply 21,000 

residential customers. 

Boiler No. 10 burns spent sulfite liquor, which is liquor that has been concentrated after the 

digestion process. Sulfur from the cooking mixture that is bound up in the spent sulfite liquor is 

liberated during combustion and converted to sulfur dioxide. An ammonia absorption tower 

captures the sulfur dioxide, which is reused in the mill. Brinks-type mist eliminators remove mist 

droplets. Particulate emissions are removed by a Dynawave reverse jet caustic scrubber located 

after the absorption tower. Sulfur dioxide emissions are further reduced by this scrubber. 

STATEMENT OF BASIS 

When the Department of Ecology issues a draft operating permit, it is required to provide a 

statement that sets forth the legal and factual basis for the draft permit conditions, including 

references to the applicable statutory or regulatory provisions. [WAC 173-401-700(8).] 

1. Assuring Compliance With All Applicable Requirements 

An operating permit must contain terms and conditions that assure compliance with all applicable 

requirements at the time of permit issuance, [WAC 173-401-600(1)]. The Department of Ecology 

has determined that the requirements listed in Appendix A to the permit do not apply to the facility, 

as of the date the permit is issued, for the reasons specified. [WAC 173-401-640(2)]. Not all of 

the inapplicable requirements are listed in Appendix A. Requirements that were considered 

obviously inapplicable were excluded from the list of inapplicable requirements. Appendix C of 

the permit contains the abbreviations used in the permit. The state Regulatory Orders that impose 

limitations and requirements on the permittee are listed in Appendix B of the permit. These 

limitations and requirements are on going. Also new sources are required to complete 

performance tests, notification and record keeping under 40 CFR 60.7 and 40 CFR 60.8. These 

new source requirements for the new hog fuel boiler (Boiler No. 14) were all completed by July 

16, 1998. 

Compliance with the conditions in the permit is deemed to constitute compliance with applicable 

requirements as contained in the permit on which the terms and/or conditions are based, as of the 

date that the permit is issued. [WAC 173-401-640(1). 

Alternate operating scenario 

The permittee did not request any other alternate operating scenario; and therefore. WAC 173-

401-650 becomes an inapplicable requirement. 

MACT Standards 

The permittee may be regulated by the 40 CFR Part 63 National Emission Standards for 

Hazardous Air Pollutants for Source Categories when they become effective. 

Application 

Ecology received a complete application prior to April 20, 1998. Therefore, the Compliance 

Assurance Monitoring (CAM) rules will be applicable in the next permitting issuance period or if a 

significant permit modification is made prior to renewal affecting specific emission unit with 
6 

potential to emit greater than major source thresholds. 

LA. Descriptions and Comments on Specific Permit Conditions 

Process Description 

Cogeneration Boiler (No. 14) 

KCTC, in conjunction with Snohomish County PUD No. 1, built a cogeneration boiler that burns 

primarily wood waste. This wood-waste boiler can produce 435,000 pounds of steam per hour as 

well as producing 325,000 megawatt-hours of electrical power. The boiler uses fabric filter 

emission control system. This baghouse includes bags of a "goretex" filtering material that 

improves filtration efficiency. Boiler No. 14 has a single emission point, the wood-waste boiler 

exhaust stack. The stack dimensions are 165 feet in height and 14 feet in diameter. 

Fuel to the new No. 14 boiler is primarily clean wood waste. Sludge from the mill's primary and 

secondary wastewater treatment dewatering filters, and mill wood and paper wastes disintegrated 

in the onsite shredder are also be burned. Additionally, up to 12 tons per day of contaminated 

wood waste may be used, under the terms of the No. 14 Boiler Fuel Plan submitted to Ecology 

June 29, 1994 (supplemented and revised July 27, 1994). The primary backup fuel for this boiler is 

natural gas. The secondary backup fuel is No. 2 distillate with a sulfur content below 0.05 percent 

by weight. Order Number DE OOAQIS-241 permits the burning of some wood containing 

creosote. 

Steam is produced for electrical power production and internal mill uses. The distribution 

between users and actual usage rates for produced steam varies over time, depending on power 

grid and mill operational demands. During maintenance or emergency shutdown situations, the 

baghouse will have to be bypassed for 2 to 3 hours. This will occur during both startup, when the 

boiler is warming up, and shutdown, when the boiler is cooling. Bypassing is necessary because 

low temperatures will cause condensation in the bags and plugging. Visible emissions may 

exceed 10 percent during periods of bypass. 

Permit Condition A.1 

The limit for NOx (180 lbs/hr) is continuously monitored to assure compliance. The limit from 

40 CFR part 60 (1 84.8 lbs/hr) is also shown for completeness. It was calculated using formula 

from the CFR and assuming oil firing. This calculation provides the most restrictive limitation 

under this regulation. A continuous emission monitor (CEM) is used to pull a sample from the air 

emissions, and analyze the NOx present. The computer part of the CEM uses the air flow 

data entered from a previous source test and the NOx present to calculate and then log the NOx 

concentration present. This information is used to calculate the pounds of NOx per hour. 

Permit Condition A.2 

The limit for CO is continuously monitored to assure compliance. 

Permit Condition A.3 

The limit for SO2 (79.2 lbs/hr) is continuously monitored to assure compliance. The limit from 

40 CFR part 60 (492.8 lbs/hr) is also shown for completeness. It was calculated using formula 

from the CFR and assuming oil firing. This calculation provides the most restrictive limitation 

under this regulation. 

Permit Condition A.4 

Yearly tests for VOC indicate virtually no emission of this pollutant. This is due to the extremely 
7 

efficient design and firing control of this unit. Some source tests have indicated no detection for 

the pollutant. Yearly source test assure compliance for this parameter. 

Permit Conditions A.5, A.6 

The limit for PM (17.4 lbs/hr) is monitored annually to assure compliance. PM10 is largely a 

function of the total PM load. The limit from 40 CFR part 60 (61.6 lbs/hr) is also shown for 

completeness. It was calculated using formula from the CFR and assuming oil firing. This 

calculation provides the most restrictive limitation under this regulation. Also shown for 

completeness is the WAC 173-410 citation (0.1 gr/dscf). This is an order of magnitude less 

restrictive than the limit set by Ecology Order DE 98-AQIO28. 

Baghouse conditions are suggested surrogate operating parameters for possible noncompliance 

with the particulate emission requirements. The baghouse condition will act as a trigger 

mechanism for taking corrective action. Exceedance of the trigger mechanisms is not by itself a 

violation of the permit. Failure to take corrective action is considered a violation of the permit. 

Permit Condition A.7 

The limit for Opacity (10%) is continuously monitored to assure compliance. The limit from 40 

CFR part 60 (20%) is also shown for completeness. Opacity is also determined through visual 

observation once a week to assure compliance. 

Permit Conditions A.1 thru A.7 limits that were arrived at through a Notice of Construction 

(NOC) Approval Order DE 98-AQIO28 per WAC 173-400-110, represent BACT for this 

emission unit. 

Process Description 

Pulping Operations 

KCTC pulp mill operations have no direct emissions or emission points. All of the exhausts, 

tank vents, and relief gases are collected and sent into the "secondary system" following the 

recovery boiler, where the great majority of pollutants are absorbed prior to discharge from the 

recovery boiler stack. The following information is provided for completeness. 

KCTC stores wood chips in piles and silos and then conveys them to the digester building, where 

they are stored in chip hoppers above each batch digester. There are currently 8 operational 

digesters. Chips and cooking acid are added to the digesters. The acid is made onsite by burning 

sulfur to produce SO2, which is combined with ammonia and water to produce the ammonium 

bisulfite cooking acid. This acid is made in the secondary system. The acid cooking in the 

digesters dissolves the lignin, leaving relatively pure cellulose. 

After cooking, the pressure in a digester is relieved by directing the gas through a series of 

accumulators and back to the secondary system. Spent sulfite liquor (SSL) is then used to facilitate 

dumping the digesters to the digester dump tanks. Emissions from these tanks also vent to the 

secondary collection system. Pulp is then pumped to the SSL washer system. The SO2 and volatile 

gases released in the pulp washing operations also enter the secondary collection system. Pulp 

washed in the countercurrent washer operation leaves the process cooled and odor free. At that 

point, the pulp goes to the screen room and the bleach plant. The concentrated spent liquor from 

the washers is sent to the evaporators and then to the chemical recovery boiler. 
8 

Process Description 

Recovery Boiler/Secondary System (No. 10) 

The No. 10 recovery boiler is a Babcock & Wilcox unit that burns spent pulping liquor and is a 

part of the acid recovery process. The boiler is capable of burning approximately 1,375,000 pounds 

of spent liquor per day and producing approximately 330,000 pounds of steam per hour. The 

exhaust gas from the boiler itself passes through a cooling tower, an absorption tower, an 

emission-control scrubber, and a demister unit before exhausting to the atmosphere. Nox is 

controlled through post-combustion ammonia injection. Acid recovery is the function of this 

process, and the absorption tower is the primary collector of S02. The emission control scrubber (a 

reverse-jet Dynawave unit) provides the final emission control step with additional SO2 and 

particulate matter control. All of the SO2 emissions collected from the pulping operations are 

controlled by this system. Boiler No. 10 has a single emission point. The stack dimensions are 202 

feet in height and 6 feet in diameter. 

The recovery boiler operates much like a base-load boiler for the mill because the chemical 

recovery operation tracks directly with the pulp production processes. Even though the digesters 

are a batch operation, there are sufficient numbers to approach a steady-state operation for spent 

liquor burning. Operational scenario options do not really apply in this case because the boiler 

burns whatever liquor is available. KCTC does have the option to burn natural gas to supplement 

the operation at times but does not routinely do so during normal operations. 

One option that occurs periodically is the washing of the No. 10 boiler booster fan. This 

fan, which provides the driving force for exhausting air from the stack, coats up with 

ammonium sulfate deposits every few months. These deposits must be washed off, and the 

washing is done during the run to avoid boiler shutdown. When washing occurs, the 

excessive water vapor that is produced clouds over the windows of the opacity monitor, 

making accurate opacity readings impossible. The monitor windows are cleaned 

immediately following the washing to enable continuous monitoring. 

Permit Condition B.1 

No specific NOx limit for this unit exists. Its NOx contribution is limited by the total NOx limit 

set for both boilers. See Permit Condition C.1 below. 

Permit Condition B.2 

The limit for SO2 (300 ppm) is continuously monitored to assure compliance. 

Permit Condition B.3 

The limit for particulate is monitored monthly to assure compliance. 

Permit Condition B.4 

The limit for Opacity is continuously monitored to assure compliance. Opacity is also 

determined through visual observation once per week to assure compliance. 

Permit Condition B.5 

The limit for ammonia is monitored annually to assure compliance. 

Permit Conditions B.6 and B.7 

These conditions require reporting of operational parameters. 
9 

Permit Condition C.1 

The combined limit for Nox is continuously monitored at both No. 14 and No. 10 Boilers to 

assure compliance. 

Process Description 

Power Boilers(Nos. 7 Through 9) 

The three power boilers at the Scott Paper Everett mill are capable of burning both natural gas 

and residual fuel oil. Boiler No. 7 was installed in 1953 and is a Riley F type, rated at 

150,000 pounds of steam per hour. Boiler No. 8 is a Combustion Engineering model BU50-BPX 

and was installed in 1954. Boiler No. 9 is identical to No. 8 and was installed in 1955. Boilers Nos. 

8 and 9 have a rating of 165,000 pounds of steam per hour. There are no emission controls on any 

of these boilers. Each boiler has its own stack, providing three separate emission points. The stack 

dimensions (for each stack) are 102 feet in height and 6 feet in diameter. 

These three power boilers provide both peak steam demand service as well as backup to the 

recovery boiler (No. 10) and the wood-waste boiler (No. 14). The mill's operational steam needs 

dictate when these boilers are running. 

Permit conditions D.1 and D.2 

These conditions require reporting of operational parameters. 

Process Description 

Catalytic Oxidizer (EM5) 

EM5 was installed in 1979. It is different from a conventional paper machine in that it uses a 

proprietary process to manufacture towel and wiper products. In this process, chemicals are 

added to the paper before it "cures" on a dryer. Some volatile organics are released during this 

curing process, so a catalytic converter was designed into the paper dryer exhaust stream when 

the machine was built. 

EM5 (as with the other paper machines) contains only categorically exempt emission units except 

for the catalytic oxidizer exhaust. A NOC for New Source Review was required for the installation 

of this pollution control device. The existence of this NOC approval (DE 79-335) requires that the 

catalytic oxidizer exhaust be classified as a significant emission unit under WAC 173-401-

530(2)(a). The exhaust gas flow from the paper dryer is initially heated to 600 to 700°F by a 

natural gas heater. The gas then flows through the catalyst section of the device. The bed is a 

honeycomb array that currently uses a platinum-based catalyst. The catalytic effect of the platinum 

effectively oxidizes the organic material at reduced temperatures. The treated gas discharges 

through a vent on the paper mill roof 

Permit condition E.1 

Limit for particulate is 50 lbs/day. Less than 5 lbs per day is emitted based on calculations using 

EPA AP 42 emission factors. Tracking gas usage is used to assure compliance. 

Permit condition E.2 

Limit for hydrocarbon is 100 lbs/day. Less than 5 lbs per day of VOC (hydrocarbon) is emitted 

using NCASI TB 646 factor for calculations. Annual source testing is performed to assure 

compliance. 
10 

I.B. Comments on Facility-Wide General Requirements 

Permit Condition 10. 

Permit condition 10 is the generic S02 limitation from WAC 173-410-040(1)(f) of 1000 ppm 

which addresses emissions from units other than a recovery system, a blow system or an acid 

plant. EPA raised the issue of compliance regarding this requirement given the discrete interval of 

testing for some units and the existence of units for which no monitoring is required. Ecology has 

imposed periodic discrete monitoring for those units deemed to warrant monitoring. Ecology has 

not imposed monitoring for units unlikely to have a reasonable potential of exceeding S02 

emission limits. 

Permit Condition 11. 

Permit condition 11 consists of two parts. The first part is an inclusion of WAC 173-400-

I05(5)(h) which allows that monitoring and reporting requirements may be temporarily 

lifted during periods of monitoring system malfunction provided the permittee adequately 

explains such periods. 

The second part of condition 11 is based on what Ecology considers an unlikely but 

possible scenario where recorded monitoring data is simply lost. Ecology will allow a 

90% recovery rate each month for monitoring data if the permittee provides an 

adequate explanation for the cause of the lost data. Ecology expects the permittee to 

make every reasonable effort to maintain the integrity of all monitoring results. An 

allowance is specified for missing monitoring results under certain conditions so that 

these defined conditions are defined as "not penalized," thus reducing the 

administrative burden on the source and the permitting authority. 

II. Insignificant Emission Units 

The facility-wide general requirements apply to the whole facility, including insignificant 

emission units and activities (IEUs), as required by the operating permit rule. The rule states, 

however, that IEUs are not subject to monitoring requirements unless the generally applicable 

requirements in the State Implementation Plan (SIP) impose them. [WAC 173-401-530(2)(c)]. 

The Washington SIP does not impose any specific monitoring-related requirements for the 

facility-wide requirements for IEUs at this source. The permit, therefore, does not require any 

testing, monitoring, reporting, or recordkeeping for insignificant emission units or activities. 

III. Regulatory Orders 

The permittee is subject to regulatory orders. Order DE 78-106 was issued to direct the sulfite 

pulp mill sources compliance with the new WAC regulation WAC 173-410. Two other orders are 

notices of construction: for pollution control equipment for a new paper machine (Order DE 79 - 

335), and the new No.14 Cogeneration Boiler (Order DE 98AQIO28). A majority of the most 

stringent emission limits for the facility are contained in these orders. 

These orders establish source-specific limitations, but also include default limitations established 

by state regulations. Orders are not intended to be separate legal sources for default limitations that 

are based in state regulations. Therefore, for limits derived directly from state regulations that were 
11 

included in Regulatory Orders for convenience purposes, Ecology considers the regulation and not 

the Order to be the "applicable requirement" for purposes of Title V. 

An important issue regarding any Title V permit is the basis of authority for the applicable 

requirements. This is particularly true regarding monitoring and reporting requirements. The basis 

of authority is used to determine federal or state-only applicability. Many of the applicable 

requirements come from orders issued by Ecology. The period of time during which these various 

orders were issued may in some cases span decades. Orders issued years ago do not clearly set 

forth the basis of authority. Also order consolidation has gone on in the past, further confusing the 

original basis of authority. Ecology decided the effort, besides being difficult, was not necessary as 

WAC 173-401-615 offered a solution to this problem. In the case of KCTC, the issue of state-only 

or federal applicability was put aside, it relies entirely on WAC 173-401-615 as the basis of 

authority for the type and frequency of monitoring. WAC 173-401-615 requires monitoring and 

recordkeeping sufficient to assure compliance with the terms and conditions of the permit. 

Monitoring and recordkeeping requirements based on this regulation are federally enforceable.