Biomass Boilers - Procedure

TIP 0416-18 ISSUED – 2008 ©2008 TAPPI The information and data contained in this document were prepared by a technical committee of the Association. The committee and the Association assume no liability or responsibility in connection with the use of such information or data, including but not limited to any liability under patent, copyright, or trade secret laws. The user is responsible for determining that this document is the most recent edition published.

Performance test procedure for boilers using biomass as fuel Scope This procedure provides the methodology to apply ASME PTC 4 – 1998 “Performance Test Code for Fired Steam Generators,” to carry out the heat and material balances and calculate the efficiency for a boiler utilizing biomass as fuel. The procedure defines the adjustments to ASME PTC 4 recommended to be followed for data acquisition, fuel sampling and analysis, and necessary calculations to test and determine the performance of a biomass fueled boiler. This procedure is not intended to apply for testing of fluid bed boilers. Any time the ASME Performance Test Code is revised, this Procedure shall be revised or adjusted as necessary to conform to a relevant provision of the revised ASME PTC 4. Introduction ASME PTC 4, Performance Test Code for Fired Steam Generators (hereinafter referred to as the “Code”), contains instructions for testing fired steam generating units. The Introduction of the Code emphasizes its limitation to steam generators fired by combustible fuels; it applies to steam generators fired by coal, oil, and gas and other hydrocarbon fuels. This Technical Information Paper applies the concepts of the Code to the testing of boilers utilizing biomass as a fuel. The biomass performance test procedure is based on a paper presented at a TAPPI Engineering Conference in 1992. The Code emphasizes the vital importance to limit the variability of the fuel by proper sampling and determination of heat value and other properties of the fuel. The Code can be used for the testing of a biomass fueled boiler by principally defining: 1) the envelope boundary for the equipment to be tested, 2) fuel-sampling, analysis and flow measurement and, 3) ash sampling, analysis and flow measurement. The proper procedures for sampling biomass fuels are the subject of TAPPI TIP 0416-17 “Sampling Procedures for Biomass Fuel for Boiler Performance Testing.” Efficiency calculated by the Energy Balance Method, also referred to as the Heat Balance Method, is more accurate (lower uncertainty) than the Input/Output Method, and is the preferred method. Accordingly, it is recommended that calculations requiring the input from fuel, (i.e., carbon loss) determine the input from fuel from the measured output using the efficiency determined by the Energy Balance Method. This Technical Information Paper sets forth for an engineer recommended adjustments to adapt the Code to establish a test procedure for testing a boiler firing biomass as fuel and achieving agreement with the general accuracy and intention of the Code. The Code and this procedure apply only when tests are run using a single fuel. Tests to be made using a combination of fuels are addressed by paragraph 5.8.3, Multiple Fuels, of the Code. Definitions The majority of definitions are in the Code, Section 2.1. Definitions included in this procedure are those peculiar to biomass and biomass combustion and testing.

TIP Category: Data and Calculations TAPPI

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Steam generating unit – a defined envelope boundary over which heat inputs and heat credits cross Biomass – For the purposes of this technical information paper, biomass is wood chips, hog fuel, milled peat, and pelletized peat Hog fuel – fuel consisting of by-product process wastes recovered for their calorific value, such as bark from wood pulping, that is sized for feed to the boiler by passing it through a chipper, or “hogger” Residue – the total solid material leaving the boiler Bottom residue (ash) – Bottom residue consists of two ash streams, front ash and siftings ash, leaving the steamgenerating unit from the bottom of the furnace Front residue (ash) – the bottom residue that is discharged from a stoker into an ash hoper to be conveyed from the steam-generating unit Siftings residue (ash) – the bottom ash that “sifts” through the grate on which the fuel is burned Gas residue (fly ash) – the residue borne from the furnace in the gaseous products of combustion backpass

Safety precautions This TIP may require the use, disposal, or both, of chemicals that may present serious health hazards to humans. Procedures for the handling of such substances set forth on Material Safety Data Sheets must be developed by all manufacturers and importers of potentially hazardous chemicals and maintained by all distributors of potentially hazardous chemicals. Prior to the use of this technical information sheet, the user should determine whether any of the chemicals to be used or disposed of are potentially hazardous and, if so, should follow strictly the procedures specified by both the manufacturers, as well as local, state, and federal authorities for safe use and disposal of these chemicals. The application of this test procedure requires personnel to come in contact with heavy machinery operating at high temperature. Where process steps are located in close proximity to the site of the boiler being tested, there is a possibility of potentially hazardous chemicals. Persons working or visiting the area should be familiar with the plant procedures for safety and evacuation. Protective clothing and caution must be used in the collection and handling of hot residue samples. Steam generator unit boundaries The diagrams for defining the steam generator unit boundaries for four alternative arrangements of the biomass boiler are indicated on Figures 1, 2, 3, and 4 (see Appendix D): Fig. 1 - Biomass boiler unit diagram without fuel dryer Fig. 2 - Biomass boiler unit diagram with fuel dryer Fig. 3 - Biomass boiler with water cooled grate within code boundary Fig. 4 - Biomass boiler with water cooled grate outside code boundary These four figures showing boundaries for arrangements of the biomass boiler are to be substituted for Figures 1.4-1 through 1.4-7 of the Code that define the steam generator inputs and heat credits crossing the envelope boundary. The envelope boundary encompasses the equipment to be included in the designation of “steam generator unit.” Bark drying utilizing sensible heat in the gaseous products of combustion is an integral part of many biomass fuel fired boiler installations. This Procedure places this equipment inside the envelope boundary. It is to be noted that a mechanical collector can be outside the boundary if there is no reinjection of ash from the collector and the gas is sampled upstream. This procedure further places the Fuel Distribution Air (Item 10) inside the envelope boundary. An alternative being applied is the use of a dedicated fan using ambient air from outside the envelope boundary, similar to the Reinjection Fan.

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Figs. 3 and 4 are for a biomass boiler with a water-cooled grate. This type of grate can be either integrated with the boiler feedwater or supplied separately. In either case, heat absorption can be significant (10,000 Btu/Hr per square foot of grate area). Fig. 3 is for a boiler with a water-cooled grate that is installed within the Code boundary. Fig. 4 is for a boiler with a water-cooled grate that is installed in an arrangement where the feed water enters (Item 13) and is heated by the water-cooled grate then leaves the Code boundary (Item 14) to pass through another feedwater heater before re-entering the Code boundary (Item 15). Further considerations for applying the code Determination of air temperature The envelope boundary will generally have two or more air streams entering the biomass boiler at different temperatures. The entering air temperature for this procedure should be the weighted average of the various entering air streams for efficiency calculations. The weight of the various streams can be determined by: • • •

Calculating the total airflow stoichiometrically from the fuel analysis and oxygen analysis of the flue gas. This is an iterative process because the heat input is not known initially. Measuring, or estimating, the minor streams. The balance of the airflow is determined by subtracting the measured streams from the total airflow.

Starting, stopping and duration of runs The provisions of the Code governing starting and stopping of a test run and the duration of a test run shall apply to testing of a boiler fueled with biomass. Fuel quantity measurement The method to determine fuel flow is to calculate fuel flow from measured heat output and calculated efficiency calculated by the input/output method Solid fuel sampling The Code is amended to provide that a representative sample of fuel be obtained in accordance with TAPPI TIP 0416-17 “Sampling Procedures for Biomass Fuel for Boiler Performance Testing.” Solid fuel analysis and high-heat value The fuel analysis and high-heat value of the fuel required by the Code are to be determined by application of the appropriate procedure listed in the methods of measurement previously stated. Heat loss due to unburned combustible in the residue The Code is amended to provide a procedure to determine the unburned combustible heat loss in the residue in accordance with Appendix A. Residue is defined as the total solid material leaving the system. This includes unburned carbon, fly ash, bottom ash and siftings ash. Appendix A describes the method of sampling for each of the residue ash streams and a recommended approach to establishing the residue flows. A representative sample(s) of residue is analyzed for carbon content. The average carbon content of the residue is finally determined to be used for calculation of the unburned carbon heat loss (UCL). Biofuels are often rich in carbonates and use of the standard LOI analysis procedure gives erroneous results due to the calcination reaction. The unburned carbon content of ash from a biofuel boiler should be determined by ignition loss at 550°C (1022°F) or by the TOC method in which the inorganic carbon, the carbonates, are removed as carbon dioxide gas by treating the residue with acid.

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The heating value of the unburned carbon content is different for the two procedures. With ignition loss at 550°C, the recommended value is 11,700 Btu/lb (27.2 MJ/kg). The recommended value with the TOC method is 14,200 Btu/lb (33.0 MJ/kg). Methods of measurement The following procedures are recommended as a supplement to the Code for the analysis of biomass fuel and its composition: ASTM E870 - Standard Test Methods for Analysis of Wood Fuels. ASTM D1102 - Standard Test Method for Ash in Wood. ASTM E711 - Standard Bomb Calorimeter Test Method for Gross Calorific Value of Refuse-Derived Fuel. ASTM E775 - Standard Test Method for Total Sulphur in the Analysis Sample of Refuse-Derived Fuel. ASTM E777 - Standard Test Method for Carbon and Hydrogen in the Analysis Sample of Refuse-Derived Fuel. ASTM E778 - Standard Test Method for Nitrogen in the Analysis Sample of Refuse-Derived Fuel. ASTM E871 - Standard Test Method for Volatile Matter in the Analysis of Particulate Wood Fuels. The following procedures are recommended for ash analysis: ASTM 3178 – Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke ASTM D1756-04 – Standard Test Method for Carbon Dioxide in Coal Keywords Biomass, Boilers, Performance tests Additional information Effective date of issue: July 25, 2008 Working Group J.L. Clement, Chairman, Clement Consulting Inc. J.R. Strempek, The Babcock & Wilcox Company– Principal Reviewer J.A.Dickinson,– The Babcock & Wilcox Company G.R. Elliott, International Applied Engineering, Inc. E.H. Mockridge, McBurney Corporation Maaret Karppinen, Metso Power Oy References Fired Steam Generators, ASME PTC 4- 1998, Performance Test Codes, The American Society of Mechanical Engineers, New York, NY, 1999. Clement, J.L., Elliott, G.R., McBurney, B. and Skowyra, R.S., Biomass Boiler Performance Test Procedure, Proceedings of TAPPI 1992 Engineering Conference, TAPPI Press, Atlanta, GA 1992. Swedish Standard “Solid fuels - Determination of the amount of unburned material in solid residues from combustion (ignition loss at 550°C)”, SS 18 71 87 “Characterization of waste. Determination of total organic carbon (TOC) in waste, sludges and sediments,” EN 13137 “Water tube boilers and auxiliary installations,” Part 15: Acceptance Tests, EN 12952-15 “Acceptance testing of steam generators,” DIN 1942.

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Appendix A. Unburned carbon heat loss determination for biomass fired boilers Objective To provide a procedure for the collection of representative residue samples composed of fuel ash and unburned carbon and data for the calculation of the heat loss due to unburned carbon from biomass fired boilers. Coordinated fuel samples are used to determine the heating value and ash content of the as-fired fuel. Fuel samples must remain in tightly sealed containers to prevent moisture loss. Establish test conditions and stabilize The boiler should be run for a minimum of four (4) hours and stabilized at the test conditions prior to the start of the test. All sootblowers should be blown prior to the start of the test and residue sampling. All residue hoppers should be evacuated prior to the start of testing. If hoppers are continuously discharged, insure that the hoppers are flowing and not plugged or backed up. Residue sampling Residue samples should be collected hourly in quart size metal sampling containers and labeled immediately. Hot samples must be tightly sealed to prevent residual carbon combustion or sprinkle water on them, if necessary, to stop or prevent ignition. Sampling ports must be allowed to purge before a sample is collected. This will avoid the collection of nonrepresentative, stagnant residue from inside the port or along the hopper walls. After residue samples are allowed to cool, they should be riffled into 2 or more separate piles as required for analysis, and may be transferred to “zip-lock” type plastic bags for easy transport. Residue samples obtained from wet hoppers should first be dried for shipment. Sampling total residue conveyed by flue gas leaving the furnace Where possible, these samples should be obtained via isokinetic or similar flue extraction methods. This will provide the most representative sample of actual operating conditions. If samples are obtained from bag house or precipitator hoppers, then all hoppers should be sampled and prepared for analysis. Bottom residue sampling. Front and siftings residue samples should be taken and analyzed separately. If they are combined into a single residue stream, the mixed residue can be analyzed. More frequent sampling of wet residue discharge systems is recommended due to the difficulty in obtaining representative samples. Residue split determination The fraction of total residue leaving the envelope at each location must be established by either estimation or direct measurement techniques. Mutual agreement of the methods used should be made prior to testing. 1.

Total residue conveyed by flue gas leaving the furnace (flue gas residue)

Flue gas residue generally ranges between 60% to 80% of total residue flow and may be determined by isokinetic sampling in the boiler backpass. If isokinetic sampling of the backpass is performed before any hoppers or drop out points, then this will be the total flue gas residue.

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Airheater hopper residue flow

Residue discharge from airheater hoppers is generally estimated to be 5% of flue gas residue flow directly upstream of that hopper. Direct measurement can be made by diverting the flow to a pre-weighed barrel or other collection device. 3.

Multiclone residue discharge flow

Multiclone residue removal rate may be estimated from Manufacturer's predictions or measured by isokinetic inlet and outlet testing. If only a portion of the residue is discharge, then this portion must be estimated or directly measured. 4.

Bottom residue flow

Bottom residue flow is usually estimated to be 20% to 40% of total residue flow or can be determined by deduction when total residue conveyed by the flue gas leaving the furnace is measured. Bottom residue should be further divided into 'Front' and 'Siftings' flows due to differences in residue make-up. Siftings flow is generally estimated to be 5% of total bottom residue flow when direct measurement is not possible. In some cases, front and siftings are combined into a single stream; this 'mixed' residue stream can then be measured and analyzed rather than measuring the two components separately.

Appendix B. Sample calculation of UCL Assume a biomass fired stoker unit is tested, with analysis of the as-fired fuel as follows: HHV = 4500 Btu/lb (8100 kcal/kg) Fuel ash = 3.0% by weight Residue split The most accurate way to determine residue split is by isokinetic sampling of the backpass. This test method is used to determine flue gas residue density and flow, and provides a representative residue sample for carbon analysis. EPA Test Methods 5 or 17 (from CFR Title 40, Part 60, Appendix A) are usually used. Sample test data and calculation sheets are included in Appendix C for reference.

Example Perform isokinetic sampling at the most suitable location for having a uniform combustion gas and residue sample, such as, the economizer outlet (see Appendix C). Measured values: Residue flow leaving with the flue gas = 1180 lb/hr Carbon content of flue gas residue = 5% by weight (by laboratory analysis of sample) At this point, the percent ash in flue gas and in bottom residue can be determined by calculating total ash from fuel input. Then, an agreed upon split of front residue and siftings can be used or directly measured. For this example, the siftings are collected for the test duration and carbon content of the siftings and front bottom residue is determined.

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Measured values: Siftings = 25 lb/hr Carbon content of siftings = 4% by weight Carbon content of front residue = 2% by weight The residue splits between flue gas, bottom front and bottom siftings is determined from the calculated total ash and measured flue gas residue and stoker siftings. The total ash flow leaving the unit is calculated from the fuel input measurement (or calculation) multiplied by the ash content of the as-fired fuel. Fuel flow = 53,760 lb/hr with 3% ash by weight Total ash flow = Fuel flow × % ash = 53,760 × 3/100 = 1,612 lb/hr Ash in flue gas residue

⎡ ⎛ 5 ⎞⎤ = 1180 × ⎢1 − ⎜ ⎟⎥ ⎣ ⎝ 100 ⎠⎦

Ash in siftings

= 1,121 lb/hr

Total Bottom Ash

= 491 lb/hr

⎡ ⎛ 4 ⎞⎤ = 25 × ⎢1 − ⎜ ⎟⎥ ⎣ ⎝ 100 ⎠⎦

= 24 lb/hr

Front bottom ash (by difference) = 467 lb/hr The total residue streams and percentages are: Residue Flue gas Front bottom = 467/ [1 – (2/100)] Siftings

Weight = 1180 lb/hr = 476 lb/hr =25 lb/hr/1681

Percentage 1180/1681 = 70.1% 476/1681 = 28.3% 25/1681 = 1.5%

The average carbon content of the residue is then determined by weighted average of the various streams. It is important to multiply by the proportions of ash refuse (i.e.: residue), not ash. Average carbon content = Σ Xi Ci where: Ci = carbon content of each residue stream. Xi = rate of each ash residue stream (carbon and ash), expressed as a fraction of the total ash residue rate.

Flue gas Siftings Front

0.701 × 0.05 = 0.015 × 0.04 = 0.283 × 0.02 =

0.035 0.0006 0.0056 0.0412 or 4.12%

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Unburned carbon heat loss

⎧ ⎫ ⎡⎛ ⎞⎤ Ash ⎟⎟⎥ × HHVC ⎪ ⎪ C in residue × ⎢⎜⎜ ⎪ ⎪ ⎣⎝ 1 − C in residue ⎠⎦ %UCHL = ⎨ ⎬ × 100 HHVF ⎪ ⎪ ⎪ ⎪ ⎩ ⎭

where: % UCHL C in residue Ash HHVC

= = = =

HHVF

=

% unburned carbon heat loss lb of carbon per lb of residue lb ash per lb of fuel from laboratory analysis Higher heating value of carbon (14,500 Btu/lb) (Refer to section “Heat loss due to unburned combustible in the residue) Higher heating value of as-fired fuel

For the example:

⎧ ⎫ ⎡ 0.03 ⎤ ⎪⎪ 0.0412 × ⎢1 − 0.0412 ⎥ × 14500 ⎪⎪ ⎣ ⎦ %UCHL = ⎨ ⎬ × 100 4500 ⎪ ⎪ ⎪⎩ ⎪⎭

%UCHL = 0.415%

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Appendix C. Example of particulate loading calculations and isokinetic sampling data sheet

Location = Meter Vol, Vm = Moist. Vol., Vlc = Meter Temp. = Meter Temp, Tm = Stack Temp. = Stack Temp, Ts = Nozzle Dia = %O2 = %CO2 = %CO = Sample time, Q = SQRT dP avg = Pitot Cal., Cp = Meter dH avg = Meter Cal. Y = Barometer, P bar = Duct, P static = Ash Weight, Mn = Fuel Factor, Ke = Duct Area, As =

ECON. 30.26 60.2 83 543 306 766 0.412 4.1 13.2 0 60 0.199 0.841 0.8775 1 29.47 -2.4 1.7747 1.3771 292

OUT CUFT g DEG F DEG R DEG F DEG R in.

Meter Vol (std) = Vapor Vol (std) = Mol Wt, Md = Mol Wt, Ms = % Moist, Bws = % Dry Gas, Fd = Nozz. Area, An = %O2+%CO2+%CO = %N2 (by diff) = Duct P (abs), Ps = Duct Dens., Dsc = Duct Dens., Dst = Duct Vel., Vs = Duct Flow, Qa = Duct Flow, Qsd = Gas Weight, Qw = Part. Conc, Cs = Part. Emiss, E = Isokinetic Var. = Part. Flow, W =

Min "WC "WC "Hg "WC g SQFT

29.03 2.83 30.28 29.18 8.89 91.11 0.000925 17.3 82.7 29.29 0.0758 0.0511 13.54 237275 145831 727612 0.943 1.62 104.67 1180.13

Calculation methods

Meter volume at dry standard conditions (ft3)

Vm( std ) =

17.64 Vm Y (Pbar + dH / 13.6) Tm

Vapor volume at standard conditions (ft3)

Vw( std ) = 0.04707 Vlc Moisture in gas (% by volume)

Bws =

Vw( std ) Vw( std ) + Vm( std )

Dry gas fraction (% by volume)

Fd = 1 − Bws

CUFT CUFT (dry) (wet)

SQFT % % "Hg LB/CUFT (std) LB/CUFT (wet) FT/SEC CUFT/MIN (wet) CUFT/MIN (dry) LB/HR (wet) GR/DSCF LB/MMBTU % LB/HR

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Dry molecular weight of gas

Md = 0.32 O2 + 0.44 CO2 + 0.28 N 2 + 0.28 CO Wet molecular weight of gas

Ms = Md Fd + 18 Bws Absolute duct pressure (in. of Hg)

Ps = Pbar + Duct density at standard conditions (lb/ft3)

Pstatic 13.6

Dsc = 0.002586 Ms Duct density at wet stack conditions (lb/ft3)

Dst =

Dsc Ps 17.647 Ts

Average duct velocity (ft/s)

Vs =

85.49 Cp Ts dP avg Ps Ms

Duct flow at wet stack conditions (ft3/min)

Qa = 60 Vs As Duct flow at standard conditions (ft3/min)

Qsd = 17.64 Qa Fd Ps Ts Gas weight at wet stack conditions (lb/hr)

Qw = 60 Dst Qa 3

Particulate concentration (g/dry std. ft )

Cs = 0.0154 Mn / Vm( std ) Particulate emission rate (lb/106Btu)

E = Cs Ke

20.9 20.9 − O2

Isokinetic variation (%)

I=

9.45 Vm( std ) Ts Q Vs Ps Fd An

Particulate flow (lb/hr)

W = 0.00858 Cs Qsd

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Appendix D. Figures

Fig. 1. Biomass boiler unit diagram without fuel dryer

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Fig. 2. Biomass boiler unit diagram with fuel dryer

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Fig. 3. Biomass boiler with water cooled grate within code boundary

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Fig. 4. Biomass boiler with water cooled grate outside code boundary

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