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 101ACKNOWLEDGEMENT

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 th e 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 SWAPCATABLE OF CONTENTS

TITLE: EMISSION TESTING STAN DARD 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 identificatio n 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

### -1- WOOD FUEL BOILER

1.0 INTRODUCTION
1.1 PURPOSE This standard provides the referee meth od for the sampling of particulate air pollutant emissions from wood fuel (hog fuel) boilers. Use of test method adaptations, adjust ments 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 vi sual determination of plume opacity is anticipated in areas where such a requ irement exists and in these instances plume opacity measurements shall be accomplished in accordance with EPA Method 9 (Ref.). Requirements for m easurement 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 particul ate 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 fu el 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 particul ate 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 subj ect to negotiation and modification. It is recommended that all __________________ compliance with emission

### -2- standards be discussed in detail ____________ regulatory agency prio r 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 pro duction rate of the boiler. Following successful completion of the test demons trating 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 mo re 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 st ack 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 st ack are not subject to the same emission limitations, compliance with the emission regulations may be demonstrated if
the test results of the combined exhaus t gases are within th e 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 st eam 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 recertif ication of the abilit y 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

### -3- boiler, then it should be used in the same relative proporatio ns to the wood fuel during compliance certification testi ng. The data sheets indicate the information which should be supplied regarding the auxiliary fuel constituents. 2.1.6 For each boiler compliance certificatio n 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 perfor med 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, 0 2 , C0 2 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 requ ire 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 temper ature 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

### -4- 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 %
H 2 0 by volume as follows:

% H20 = 

### Ps Psv 100

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 0 2 , C0 2 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 connect ed 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 c onstant rate during the test run. b. Sample analysis. Analysis of the collected sample requires at least three
determinations for C0 2 , 0 2 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 < %C0 2 +0 2 +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.

### -5- 3.2.2 Sources employing wet scrubb ing 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 si x determinations of C0 2 , 0 2 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. Th e results are averaged, and must all agree with the relationship
19.1 < %C0 2 +0 2 +1/2%C0< 21.5 Fyrites are not acceptable because th ey 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 in struments (7) design ed to measure 0 2 and/or
C0 2 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 < %C0 2 +0 2 +1/2%C0< 21.5 the problem may be due to absorption of C0 2 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 shou ld 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

### -6- elemental areas per Table I or equivalent. 4.2.3 In rectangular ducts, the number of ve locity traverse points shall be determined from Figure 1, and located at the centroid of equal elemen tal areas. The ratio of length to width of elemental areas are recommended to not exceed 2 to 1. An equivalent round diameter for a rect angular 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 measure ment. Velocity instruments with an accuracy measurement with + 0.01” H 2 0 are most desirable.
4.4 VELOCITY CALCULATION 4.4.1 Procedure: The following procedure or equivalent may be used to perform the
calculations

v s = K P C P (t s xDelta P ) avg/p s M s ) 1/2 vs = Stack gas velocity, feet/sec.
K P = 85.48 (ft/sec.) (Lb/lb mole – o R) 1/2
C P = Pitot tube coefficient, dimensionless
T s = Absolute stack gas temperature, o R Delta = Velocity head of stack gas, in. water column
P s = Absolute Stack Gas Pressure, in. Mercury column
M s = 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 (T s x Delta p ) and divide by the number of readings to
determine T s x Delta p ) 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 PO INTS – 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.)

### -7- 5.1.2 Particulate sampling may be conducted at the minimum number of sampling traverse points as specified in Figu re 1. (Not less than 12.)
5.2 SAMPLING PORTS: Ports should be ad equately sealed to prevent velocity fluctuations near port openings.
5.3 TEST RUN: A test run consists of co llecting one sample at all elemental areas as specified in 11, A, Number of Points. 5.4 WALL CLEARANCE: Sampling nozzle shal l 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 co llective velocity data and/or samples at all specified points (equal elemental ar eas) 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 co gnizant procedure.-8-

### -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 ho lder (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 prob e 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, summar y 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 composit ion, fuel com position, 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 deviat ion 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% C0 2 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 fo rm 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 GENE RATION RATE DATA The following data should be recorded for each test run: Date: ____________ Run. No.: ___________ Steam Pressure (psig): Average Boiler Steam Generation Rate During Tes t: __________ (lbs/hr)
Peak Boiler Steam Generation Rate During Test: _________ (lbs/hr)
Minimum Boiler Steam Generation Ra te 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 percenta ge 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 ______________%

### -13- What is the moisture content of th e mixed wood fuel on a “wet” basis? _____________% If the boiler is equipped with a cinder reinjection system, were the cinders being injected dur ing 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 ______________%

### -14- Form 8.2 ORSAT ANALYSIS DATA SHEET Source ____________________________________________ Date Sampling Point Location

RUN _________

C0 2 

### 0 2 

### CO N 2 

### Time Analysis 1 Test Conditions Analysis 2 Analysis 3 Average

C0 2 

### 0 2 

### CO N 2 Atomic Wt. (44) Atomic Wt. (32) Atomic Wt. (28) Atomic Wt. (28

______ + ______ + ______ + ______ + 

### = Total Atomic Wt. RUN _________

C0 2 

### 0 2 

### CO N 2 

### Time Analysis 1 Test Conditions Analysis 2 Analysis 3 Average

C0 2 

### 0 2 

### CO N 2 Atomic Wt. (44) Atomic Wt. (32 Atomic Wt. (28) Atomic Wt. (28)

______ + ______ + ______ + ______ + 

### = Total Atomic Wt.

### -15- 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. H 2 

### 0 ( ∆ P x Ts) S = xTs P ∆



### 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 = _________________-16-TotalAvg.PARTICULATE SOURCE _____ING FIELD DATAOrifice, H in H20 Dry Gas Temp tm, °FClockTime Point No.Dry GasMeterQm, ft3Pitot P“H20Desired Actual Inlet OutletPumpVacuum“HgStackTemp. ts,°FFilterTemp. °FImpingerTemp. °FStackOpacityComments: Avg. gas temp. tm ° FRun No. _________PlantSampling LocationDateOperatorAssistantIMPORTANTNozzle Dia., Dn = _______ in.Heater Box Setting ______ °F“C” Factor ______ @ ____ °FAssumed Moisture _____ Vol. %Ambient temp. _____________°FBar. Pressure, Po = _________in. HgBegin Sampling timeSampling time intervalProbe heater settingStack pressure __________ in. H20

### -17- 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 RESULTSSymbol 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 H 2 0 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 xTs P ∆ 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 ( 7

. 17

+ = tm Qm Qd (Po + 6

. 13

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 = Qd Qv Qv

+ 100

md Mole fraction of dry gas Md = Qd Qv

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 (

Ms Ps 1 ) 2 1

qs Stack flowrate at st. conditions, scfm qs = Ts Ps md As Vs ) )( )( )( ( 123

. 0

I Percent Isokinetic I = ) )( 2 )( )( )( ( 1032
t Dn md Ps Vs TsQd ∆ W Wt. of particulate sample, gm Total from Lab Data Sheet Cg Total Particulate grain loading, gr/scf Cg = Qds W 154

. 0

C’g Grain loading at 12% C02 gr/scf Cg’ = Cg x ) 2 (%

012 CO Ct Total particulate em ission, lb/hr Ct = .00857 (Cg) (qs)

### -19- 9.0 REFERENCES 1. Vol. 36, No. 247, Part 2 of th e 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 Sampli ng Training Manual, 1972 American Institute of Chemical Engineers 345 E. 47 th 

### 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,” We stern Precipitati on Division, Joy Manufacturing Co., 1000 West 9 th 

### St., Los Angeles, CA 90015 7. ASME Performance Test Coce #19.10 (1968)

### -20- 10.0 APPENDIX 10.1 Carrier’s Equation

% H 2 

### 0 = PSV - Ps tw tw td Psv Ps 100 3

. 1 2800 ( ) (

− − −

tw = wet bulb temperature, °F td = dry bulb temperature, °F Psv = saturation vapor pressure at tw (a vailable from tables (6), inches Hg. Ps = absolute static pressure in stack, inches Hg.
10.2 Conversion of lbs. H 2 

### 0/lb. dry air to % H 2 

### 0 by volume

% H 2 

### 0 = 

## ( )

W W

+ 29 18 100



### W = lbs. H20/lb. dry air avai lable 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, ft 3 

### or scf
S = T x P 

### t = temperature, °F T = absolute temperature, °R u = velocity, fpm V = liquid volume, ml W = mass or weight, gm
∆ H = orifice pressure drop, in. H 2 

### 0
∆ P = pitot tube differential pressure, in. H 2 

### 0-21-

### -22- water is evaporated. Desiccate a nd 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 an d chloroform extracts, transfer to a tared beaker and evaporate at 70 degr ees F. until no solvent remains. Desiccate 24 hours and dry to a consta nt weight and report the results to the nearest 0.1 mg. Determine impinger water non-extractables (inorganics) by evaporati ng extracted water solution at no more than 100 degrees C. (use of steam table is pr eferred). 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 collect ed particulate as well as the constituents separately as follows:
a. Prefilter acetone wash.
b. 1 st 

### filter weight gain
c. Extractables d. Impinger water residue e. Impinger train acetone wash. 19.46.2.2 Report physical characteristics of co llected particle specimen’s as follows: a. Particle size (visually determined extent of particles over approximately 50 microns in diam eter 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 th e 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 pa rt 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 tissu e 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-mechanic al pulp, and recycled fiber to manufacture tissue products for both the commercial and consumer markets.
In general, wood chips are cooked with acid in digest ers 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 st orage. An ammonia absorption tower recovers sulfur dioxide. The mill's unit pr ocesses 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 s ilos. 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-ba tch digesters by using heat and chemicals. The cooking process separates the wood into its primar y 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 an hydrous ammonia, molten sulfur, and water. Each process unit is hooded and vented to th e 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 dige sters and evaporators. The pulp is sent through screens and washers be fore 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 treatm ent 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 sen t to secondary wastewater treatment system.

Screening, Drying, and Baling The bleached pulp is screened and centrifuged to re move dirt and contaminants from the finished pulp. Rejected material is sent to primary treatme nt. At this point, the cleaned pulp may be used immediately in the paper mill, or it may be drie d on the pulp drying machines and stored for later use and/or sale. When needed, the dried pulp is we tted in a repulper to form a slush to be sent to the paper mill. Some of the dried sulfite pulp is al so 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 rew ound 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 wr apped 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 br oke, 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 th e dyes and to aid defibering by breaking down chemicals in the paper. Hypochlorite is consumed by the reacti ons 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 av ailable to supply steam for plant operations: one cogenerating wood-waste boiler, three dual-fuel bo ilers, and a recovery boiler. Boiler No. 14 is a woodwaste boiler ( installed in 1995) produces about 435,000 pounds ofsteam 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 recove ry boiler. The recovery boiler is used to burn spent sulfite liquor, and is capable of producin g 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 comp anies, and consists of sawdust, bark, and other wood waste. In addition, KCTC burns appr oximately 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 bagh ouse to remove particulate material. The boiler



### 5

### 5 is part of a cogeneration facility that meets plan t steam needs, and also generates a total of a bout 325,000 megawatt-hours of electrical power per y ear. 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 th at 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 th e 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 emis sions 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 le gal and factual basis for the dr aft 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 conditi ons 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 reas ons specified. [WAC 173-401-640(2)]. Not all of the inapplicable requirements are listed in A ppendix 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 th e permit. The state Regulatory Orders that impose limitations and requirements on the permittee ar e listed in Appendix B of the permit. These limitations and requirements are on going. Al so new sources are required to complete performance tests, notification and record k eeping under 40 CFR 60.7 and 40 CFR 60.8. These new source requirements for the new hog fuel boile r (Boiler No. 14) were all completed by July 16, 1998.
Compliance with the conditions in the permit is de emed to constitute comp liance with applicable requirements as contained in the permit on which th e 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 altern ate 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 Cate gories 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 Sno homish 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 elect rical 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. Additi onally, 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, 19 94). The primary backup fuel for this boiler is natural gas. The secondary backup fuel is No. 2 dis tillate with a sulfur content below 0.05 percent by weight. Order Number DE OOAQIS-241 pe rmits the burning of some wood containing creosote.
Steam is produced for electrical power productio n and internal mill u ses. The distribution between users and actual usage rates for produced steam varies over time, depending on power grid and mill operational demands. During maintena nce or emergency shutdown situations, the baghouse will have to be bypassed for 2 to 3 hour s. 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 th e 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 mon itor (CEM) is used to pull a sample from the air emissions, and analyze the NOx present. The co mputer part of the CEM uses the air flow data entered from a previous source test and th e NOx present to calculate and then log the NOx concentration present. This information is u sed 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 SO 2 (79.2 lbs/hr) is continuously monitore d to assure compliance. The limit from 40 CFR part 60 (492.8 lbs/hr) is also shown for completeness. It was ca lculated using formula from the CFR and assuming oil firing. This calcula tion 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 a nnually 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 ope rating 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 correctiv e action is considered a violation of the permit.

Permit Condition A.7 The limit for Opacity (10%) is continuously m onitored 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 th rough 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 emissi ons 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 po llutants are absorbed prior to discharge from the recovery boiler stack. The following info rmation 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 th e digesters. The acid is made onsite by burning sulfur to produce SO 2 , 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 re lieved 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 SO 2 and volatile gases released in the pulp washing operations al so enter the secondary collection system. Pulp washed in the countercurrent washer operation l eaves the process cooled and odor free. At that point, the pulp goes to the screen room and the bl each plant. The concentr ated 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 approxima tely 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 be fore exhausting to the atmosphere. Nox is controlled through post-combustion ammonia injecti on. Acid recovery is the function of this process, and the absorption tower is the primary co llector of S02. The emission control scrubber (a reverse-jet Dynawave unit) provides the fina l emission control step with additional SO 2 and particulate matter control. All of the SO 2 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-lo ad boiler for the mill because the chemical recovery operation tracks directly with the pul p 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 ha ve 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 wa shing of the No. 10 boile r booster fan. This fan, which provides the driving force for e xhausting air from the stack, coats up with ammonium sulfate deposits ever y 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 impossi ble. 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 continu ously monitored to assure compliance.

Permit Condition B.3 The limit for particulate is monito red monthly to assure compliance.

Permit Condition B.4 The limit for Opacity is continuously monito red 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 reportin g of operational parameters.

### 9 Permit Condition C.1 The combined limit for Nox is continuously m onitored 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 Evere tt mill are capable of burning both natural gas and residual fuel oil. Boiler No. 7 was insta lled 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, pr oviding 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 bo iler (No. 14). The mill's operational steam needs dictate when these boilers are running.

Permit conditions D.1 and D.2 

### These conditions require reporti ng of operational parameters.

Process Description Catalytic Oxidizer (EM5) EM5 was installed in 1979. It is different fro m 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 desi gned 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 Ne w 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 dr yer 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 re duced 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 lim itation 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 regardi ng 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. Th e 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 ma lfunction 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 monitori ng 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 monitori ng requirements unless the generally applicable requirements in the St ate Implementation Plan (SIP) impo se them. [WAC 173-401-530(2)(c)]. The Washington SIP does not impose any specifi c monitoring-related requirements for the facility-wide requirements for IEUs at this sour ce. 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. Or der DE 78-106 was issued to direct the sulfite pulp mill sources compliance with the new WAC re gulation 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 pur poses, 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 regard ing 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 d ecades. Orders issued years ago do not clearly set forth the basis of authority. Also order consolid ation 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 reli es entirely on WAC 173-401-615 as the basis of authority for the type and frequency of m onitoring. WAC 173-401-615 requires monitoring and recordkeeping sufficient to assure compliance w ith the terms and conditions of the permit. Monitoring and recordkeeping requirements based on this regulation are federally enforceable.