Babcock Borsig Power, Inc.Post Office Box 15040

Worcester, MA 01615-0040www.bbpwr.com

TECHNICAL PUBLICATION

RST-162

UNIQUE BOILER DESIGN FLEXIBILITYFOR A WIDE RANGE OF COAL PROPERTIES

ForCGESJ San Jose Guatemala Project

byRichard Dube, P.E.

Senior Consultant, Fuel Equipment DesignCraig Gillum

Staff Engineer, Boiler DesignKevin Toupin

Manager, Boiler DesignBabcock Borsig Power, Inc.Worcester, Massachusetts

andJon Erickson, P.E.

Black & VeatchOverland Park, Kansas

Presented at Power-Gen2000 InternationalOrlando, Florida

November 14-16, 2000

© Babcock Borsig Power, Inc. 2000

UNIQUE BOILER DESIGN FLEXIBILITY FOR A WIDE RANGE OF COAL PROPERTIES

ForCGESJ San Jose Guatemala Project

byRichard Dube, P.E.

Senior Consultant, Fuel Equipment Design

Craig GillumStaff Engineer, Boiler Design

Kevin ToupinManager, Boiler Design

Babcock Borsig Power, Inc., Worcester, Massachusetts

andJon Erickson, P.E.

Black & Veatch, Overland Park, Kansas

ABSTRACT

Between 1996-1999, Babcock Borsig Power, Inc. was involved with the design and supplyof a unique coal fired boiler design for JA Jones-Black & Veatch Joint Venture (JBV) on theCGESJ (TECO Power Services and Local Guatemalan Partner) San Jose Guatemala Project.Part way through the design phase, a coal with properties outside the design fuel range wasidentified to be the first coal to be fired. This new coal was a South American coal with a com-bustion history of increased carbon in the ash, increased coal hardness, increased coal mois-ture and increased furnace slagging characteristics. The design features which allow for oper-ating flexibility to combust the new coal include:

• Unique tubular airheater design similar to a Trisector Regenerative Airheater tosignificantly increase the pulverizer primary air temperature;

• Coal pulverizers capable of handling the South American coal’s low Hardgrovegrindability index and high moisture

• Strategically placed furnace sootblowers to control the furnace exit gas tempera-tures

• Wide range of superheater attemperator spray flow capacity to control the finalsteam temperatures

• Added balancing damper to allow changes in primary to secondary air flows(manual biasing damper)

2

Babcock Borsig Power, Inc.’s low-NOx Controlled Combustion Venturi (CCV®) Dual AirZone burner design is a versatile burner design that can be adapted to a broad range of coalcharacteristics. Therefore, a significant change in coal moisture and volatile content was notexpected to affect the ability of the burner to meet NOx emission requirements. However, forgreater flexibility, the burner was designed to accommodate at least two coal nozzle sizes, ifnecessary. Acceptance testing following boiler start up in late 1999 revealed that the boilerexceeded its guarantees with the original nozzle size.

Because the South American coal was significantly different from the original design coal,a set of curves relating boiler and combustion performance with the two coals was developed.These curves were used to evaluate the acceptance test results against the contract perfor-mance guarantees. The acceptance test results demonstrated that the boiler met or exceededits performance guarantees. The acceptance testing also showed the importance of coal andash sampling on the test results.

This paper discusses the coal differences, the furnace/boiler design considerations, theburner and pulverizer designs and the unique tubular air heater design. Highlights of the testplan, procedure and results are also presented.

Principal Owners: CGESJ (TECO Power Services & Local Guatemalan Partner)

Engineers: Black & Veatch, KS

Boiler and Combustion System Supplier: Babcock Borsig Power, Inc., MA

1.0 INTRODUCTION AND BACKGROUND

In 1996 Babcock Borsig Power, Inc. (formerly DB Riley, Inc.) was contracted by JBV todesign and supply a coal fired boiler and combustion system for the CGESJ San JoseGuatemala Project. The boiler and combustion system was commissioned during the fall andwinter of 1999. Refer to Figure 1.1 for a side view of the boiler and combustion system gen-eral arrangement and a summary of the predicted boiler performance.

Boiler Design

The boiler has a Maximum Continuous Rating (MCR) steam flow of 1,104,310 lbs/hr andis designed to operate with outlet steam conditions of 1005°F and 1965 psig. Steam temper-ature control is by spray attemperation. The boiler has a steam temperature control rangedown to 70% of its MCR rating. The boiler is arranged with burners located on the furnacefront wall and has a single convection pass design.

Combustion System Design

The combustion system is comprised of three coal pulverizers feeding a total of twelvelow NOx burners. The burners are arranged in three rows. Each pulverizer supplies one rowof four burners. When firing the original specified coal, the system is designed to carry MCRsteam flow with two coal pulverizers in service.

New Coal Introduced

During the contract design phase, a coal that was outside the original design range wasselected by the owner. The type of coal being burned influences the overall design of the boil-er and combustion system. The boiler and combustion system performance guarantees werebased on a bituminous coal from British Columbia, Canada, with a design that included a

3Figure 1.1 Boiler and Combustion General Arrangement Drawing

Coal Fired1,104,310 pph Steam Flow

1005°F Superheater1965 psig

Front Wall FiredTwelve Controlled Combustion Venturi (CCV®) Dual Air Zone Burners

Tubular Airheater

4

broader fuel range. Well into the design, the El Cerrejon coal from Columbia, South Americawas identified as the coal to be first fired, and this coal has properties outside the designrange. Although both the El Cerrejon and the specified coal are bituminous type coals, thereare several significant differences. These differences include Hardgrove index (HGI), mois-ture content, slagging/fouling properties and combustion characteristics.

• Hardgrove

The Hardgrove index dropped from an expected typical of 75 for the specified coal,to an El Cerrejon coal expected typical of 48 (it turned out that the HGI droppedas low as 38 during actual testing). The change in HGI affected coal pulverizercapacity, power consumption and coal fineness but had no real effect on the boil-er design.

• Moisture

The normal moisture content of the El Cerrejon coal was slightly higher than thespecified coal but did not have a significant effect on the overall design of the boil-er. Due to the climate in Guatemala, it was expected that during the rainy seasonany coal could have a moisture content as high as 20% regardless of its typicalmoisture content. This high moisture content dictated the design for both coals.As it turned out, due to the method of transport and storage at the site, the coalbecame supersaturated with water and at times, reached the milling system innear slurry form. When this condition occurs, the moisture content is well above20% and it is often necessary to reduce boiler load due to pulverizer capacity lim-itations.

• Slagging/Fouling Characteristics

A comparison of the standard ash indices of both coals showed that they wereexpected to behave as low slagging and low fouling coals. However, BabcockBorsig Power, Inc. has had previous experience firing El Cerrejon coal. When firedin a boiler subject to cycling duty, the ash sheds at night when boiler load isreduced and the coal appears to be low slagging. When the boiler is base loaded,the ash does not shed. After several days of operation, a coating of ash forms onthe tubes. Though the ash layer is not thick, the ash that does adhere to the tubesis highly reflective, with the result being the coal behaves like a medium to highslagger. The slagging and fouling properties of the two coals had the greatestimpact on boiler performance.

• Flyash Unburned Carbon Content

The originally specified performance guarantee coal would produce a predictedunburned carbon boiler efficiency loss of 1.26%. Firing the El Cerrejon coal, basedon the existing Guatemala furnace design, produced an actual unburned carbonboiler efficiency loss of 2.2 - 2.6 %. The evaluation of possible causes for theincreased unburned carbon loss firing El Cerrejon is reviewed in the attachedsub-discussion on El Cerrejon Coal. Table 1.1 lists both the original specified coaland the new El Cerrejon coal.

5

Table 1.1 Original Specified Coal vs El Cerrejon Coal Comparison

Proximate Analysis Specified Coal El Cerrejon Coal% by weight Design Normal Range Design Normal Range

Moisture 8 8-13, 20 Max 11.6 10.7-12.5, 20 MaxAsh 15.5 5-15.5 7.4 6.4-8.4Volatile matter, VM 21-24 21-36 33.4 32.46-34.34Fixed Carbon, FC 52.5-55.0 Not specified 47.6 Not specifiedChlorine 0.02 0.0-0.02 0.04 0.0-0.04Sulfur 0.4 0.4-0.6 0.65 0.51-0.79HHV, Btu/lbm 11,350 11,350-12,200 11,800 11,700-12,000

HGI 50 50-80 48 43-52

Furnace Slagging Index Low — Med-High —Convection Pass

Fouling Index Low — Low —

Unburned Carbon 3.19% PredictedBoiler efficiency Loss 2.2-2.6% Actual

1.26% Predicted — —

2.0 BOILER DESIGN

2.1 Boiler Arrangement

The boiler is a flat wall, front fired single pass design. The furnace is a water-cooled weld-ed membrane design. The backpass side and rear walls are steam cooled. The boiler fires pul-verized coal and is equipped with twelve CCV® Dual Air Zone burners and three 558 DuplexATRITA® Pulverizers. The boiler is designed to operate at full load with two pulverizers inservice. When firing high moisture coal, all three pulverizers are required to be in operationto reach MCR.

Flue gas from combustion passes over a platen radiant superheater located in the upperfurnace. The flue gas leaves the furnace and passes over a pendant type secondary super-heater, flows across a bank of screen tubes, and enters the convective back pass. In the con-vective back pass, the gas flows downward across a horizontal primary superheater bundleand then across three horizontal economizer bundles. The flue gas then passes through theexit breeching and into the three-pass bi-sector tubular air heater.

The tubular air heater is comprised of two sections. The first section consists of the airheater’s third pass. It is located beneath the boiler convective backpass. The flue gas exitsfrom the air heater third pass, makes a 180° turn, and then flows upward through the sec-ond section of the air heater (which consists of the first and second passes). The flue gasleaves the air heater and flows into the pulse jet fabric filter through the ID fan and thenout the stack.

On the steam side, saturated steam leaves the drum and is conveyed into the rear halfof the convective side walls. The steam flows down the rear half of the convective sidewalls,collects in the lower header, and then flows up the front half of the convective sidewalls. Thesteam flows into the upper convective rear wall and roof header and then flows down theconvective rear wall. Upon leaving the convective rear wall at the bottom of the backpass,transfer pipes carry the steam into the primary superheater bundle. Steam leaves the pri-mary superheater bundle and passes through the spray attemperator and into the radiant

6

EL CERREJON COAL REVIEW

The South American coal from the El Cerrejon seam is a bituminous coal known through-out the power industry as having low ash content and different combustion characteristicswhich results in increased unburned carbon loss as calculated for boiler efficiency. Theincrease in carbon loss is associated with existing boilers originally designed for NorthAmerica Bituminous coal and retrofitted to burn El Cerrejon coal. For the associatedGuatemala furnace design, furnace retention time and operating conditions the boiler effi-ciency unburned carbon loss increased from the predicted 1.26% firing North AmericanBituminous coal to 2.2 - 2.6% firing the El Cerrejon coal.

El Cerrejon coal produces increased carbon loss for several reasons, some of which arediscussed below.

• The coal is harder which in turn reduces coal fineness and pulverizer capacity.Although the coal fineness met the guaranteed values of 98% thru 50 mesh and 70%thru 200%, the fineness is less than a typical North American bituminous coal for thesame coal throughput.

• The El Cerrejon coal is significantly less reactive than most coals. Babcock BorsigPower, Inc. conducted laboratory studies of the El Cerrejon coal and found that the coalcontains a large quantity of inertinites (unreactive macerals) adversely affecting com-bustion efficiency and unburned carbon in the ash.

• The mineral matter of the El Cerrejon coal tends to be concentrated and isolated fromthe carbon particles rather than uniformly dispersed throughout the coal. Minerals inthe coal particles can act as nucleation sites for combustion. Uniform dispersion of min-erals breaks up the coal particle, thereby increasing combustion efficiency. Non-uni-form dispersion of minerals has the opposite effect, which is exactly the case with ElCerrejon coal.

• Further, the flyash from combustion of the El Cerrejon coal was analyzed using com-puter controlled scanning electron microscopy (CCSEM). For the same coal fineness,the data showed that the flyash particles for El Cerrejon coal are significantly largerthan those of the US and the British Columbian coals used for comparison. The dataindicated that there may have been some agglomeration or coalescence of the parti-cles during the combustion process.

The less reactive coal, non-uniform dispersion of minerals, and the agglomeration of par-ticles contribute to poorer combustion efficiency adversely affecting carbon loss.

Note: For new boilers specifically designed to burn El Cerrejon coal, the following designfeatures should be evaluated to reduce carbon loss:

• Increase furnace retention time (taller furnace) between top burner elevation and fur-nace exit

• Increase combustion zone temperatures (refractory on wall in the combustion zoneand/or increased hot air temperature)

• Smaller plan area

• Tight burner spacing

• High burner zone heat release (vertical and horizontal)

7

superheater. Steam flows through the radiant superheater and then into the parallel flowsecondary superheater. The steam exits the secondary superheater and flows to the turbine.

2.2 Effect of the El Cerrejon Coal on Boiler Design

One of the largest influences on the overall design of the boiler is the type of coal beingburned. As noted in the introduction, the slagging and fouling properties of the two coals hadthe greatest impact on boiler performance. Changing from a low slagging to a medium-highslagging coal had potentially profound implications on the design of the boiler. With the coalchange occurring well into the design phase, increasing furnace size to accommodate themedium-high slagging nature of the coal was not an option.

Based on our experience firing El Cerrejon coal, we knew that the slag buildup was eas-ily removed by sootblowing. Knowing that the ash could be removed, we knew furnace exittemperature could be controlled, although it would still run somewhat hotter then it wouldwith a low slagging coal. Using our historical database of furnace performance, we were ableto develop a new set of performance conditions for the furnace based on a medium slaggingcharacteristic coal.

The new performance predictions showed an increase in the furnace exit temperatureand a resulting increase in superheater spray flow. Owing to the configuration of the super-heaters, steam temperatures entering the radiant superheater were high enough so that theincrease in spray flow could be accommodated without spraying to saturation at the inlet ofthe radiant superheater.

The difference in boiler performance as a result of changing coals is highlighted in Table2.1.

Specified Coal El Cerrejon Coal

Slagging index Low Medium-High

Flue gas produced (lbm/hr) 1,300,000 1,313,000

Furnace Heat Release Rate (Btu/hr-ft2) 51,195 51,535

Radiant superheater Q/A (Btu/hr-ft2) 15,355 16,420

Furnace Exit Gas Temperature (°F) 1,835 1,885

Spray flow (lbm/hr) 47,000 78,000

Steam temperature before spray (°F) 776 795

Steam temperature after spray (°F) 731 719

Saturation temperature (°F) 645 645

Table 2.1 Comparison of Performance Between the Specified and El Cerrejon Coals

To accommodate these differences, the following approach was taken:

1. Sootblowers were strategically located to maximize furnace cleaning to control fur-nace exit gas temperatures.

2. Capacity of the superheater spray attemperator was increased to accommodate theincrease in spray flow.

3. Superheater tube material was reselected, taking into account the higher tempera-tures and heat fluxes.

8

2.3 Economizer Surface Optimization

Because the original coal had a low volatile content, carbon loss was expected to be a lit-tle higher than typically expected for bituminous coals. The decision was made early on inthe contract to add heating surface to reduce air heater exit gas temperature as much as pos-sible and maximize boiler efficiency. Because the structural steel design was fixed at the out-set of the contract, the overall height width and depth of the boiler was fixed. As such, onlysurface additions that did not increase the overall dimensions of the boiler could be consid-ered. The layout of the convective backpass was such that additional economizer surfacecould be added without increasing the overall height of the boiler.

The decision to add surface proved especially fortuitous in light of the coal change. It suf-fices to say that with carbon loss expected to increase with the El Cerrejon coal, having alower air heater exit gas temperature would help recover some of this loss in efficiency.

2.4 Innovative Tubular Air Heater Design

Increasing economizer surface to lower exit gas temperature decreased the gas temper-ature leaving the economizer, resulting in a decrease in air temperature leaving the airheater. The air temperature leaving the air heater dropped 70°F, from 585°F to 515°F. Inorder to ensure sufficient energy is available for drying the El Cerrejon coal, a minimum airtemperature to the pulverizers of at least 570°F is recommended.

To provide higher temperature air for drying of the coal, the airside of the air heater waspartitioned to form a separate primary air section within the confines of the original enve-lope. This approach was necessary because the external dimensions of the boiler had beenfixed and the air heater could not be made any larger.

Primary airflow is approximately 15% of the total combustion air. In order to maximizeprimary air temperature, the air heater was partitioned so that 20% of the surface area wasallocated for the primary air and 80% of the surface was allocated for the secondary air. Thisconfiguration actually resulted in a primary air temperature of 580°F. Figure 2.1 shows asketch of the partitioned air heater.

Figure 2.1 Partitioned Three-pass Tubular Air Heater

9

Critical to the performance of the partitioned air heater is the manual biasing damperinstalled in the secondary air duct to the windbox. Initially installed to increase back pres-sure in the system and provide a higher inlet pressure at the inlet to the pulverizers, thedamper now provides additional means to adjust the primary/secondary air split throughthe partitioned air heater. Figure 2.2 is a schematic showing the location of the manual bal-ancing damper. Table 2.2 lists the partitioned and unpartitioned tubular air heater perfor-mance.

Figure 2.2 Biasing Damper

Table 2.2 Comparison of Partitioned and Unpartitioned Air Heater Performance

Unpartitioned Partitioned

Boiler Load (%MCR) 97 97

PA/SA Surface Area Split (%) 20/80 20/80

Total Combustion Air Flow (lbm/hr) 1,158,000 1,158,000

Primary Air Flow (%) 12.3 12.3

Primary Air Temperature (°F) 511 562

Secondary Air Temperature (°F) 511 490

Air Heater Gas Temperature (°F) 286 285

Air Heater PA Side Air Pressure Loss (iwc) 6 2.24

Air Heater SA Side Air Pressure Loss (iwc) 6 6.93

Pressure Required at FD Fan Discharge (iwc) 12.92 13.85

10

3.0 COMBUSTION SYSTEM REVIEW

3.1 Burners

The boiler is equipped with Babcock Borsig Power, Inc.’s CCV® Dual Air Zone Burners.This burner incorporates the latest enhancement to the Babcock Borsig Power, Inc.’s lowNOx coal burner technology. As shown in Figure 3.1, the CCV® Dual Air Zone Burner pro-vides independent control of secondary and tertiary air in two concentric passages sur-rounding the patented CCV® coal nozzle which incorporates a low swirl coal spreader design.

Figure 3.1 Controlled Combustion Venturi (CCV®) Dual Air Zone Burner

The secondary air inlet passage of the CCV® Dual Air Zone Burner contains adjustablesecondary air dampers for controlling the flow split between secondary and tertiary air aswell as the near field burner zone stoichiometry. A set of axial swirl vanes is used to impartthe required degree of swirl necessary for good flame attachment and shape. Tertiary airflow is controlled by the burner air shroud while another set of axial swirl vanes in the ter-tiary air annulus control the mixing of tertiary air into the combustion process.

The boiler has twelve CCV® Dual Air Zone Burners, eight of which must be able to carryfull boiler load on the original specified design coal. The contract required that the burnersmeet or exceed a NOx emission level of 650 mg/Nm3, dry basis at 6% O2 (0.53 lb/106 Btu).The original contract coal had a relatively low volatile content of less than 20 %. El Cerrejoncoal has a volatile content of greater than 33% (refer to Table 1.1). The burners had alreadybeen selected and the boiler and the burner designed for the low British Columbia volatilecoal.

The new El Cerrejon coal had a lower NOx prediction than the original contract coal; infact, with eight of the twelve burners in service, the actual measured NOx at the economiz-er outlet was less than 0.46 Lb./106Btu as compared to the guaranteed value of 0.53

11

Lb./106Btu. This NOx value is with burners only, since the boiler was designed without anoverfire air system.

3.2 Burner Start-Up Adjustments

During initial startup, the coal was very wet at times, well beyond its design maximumof 20 % moisture, as received. This is a common occurrence in Guatemala during rainy sea-sons. This affected the burners and the mills (see the pulverizer section for further discus-sion of this subject).

Flame stability, caused by poor flame attachment at low loads, was also an issue.Adjusting the burner tertiary air spin vanes helped but did not solve the problem complete-ly. Babcock Borsig Power, Inc. decided to reduce the primary air velocity by reconfiguring thecontrols curve of primary air vs. mill load. The original curve dropped to 80% at 33% millload as shown in Figure 3.2. The revised curve dropped to 70% at 33% mill load as shown.This change in primary airflow resulted in a significant improvement in burner performanceat low mill loads. The flame was more attached and much more stable.

Figure 3.2 Primary Air Flow vs Mill Load

3.3 Pulverizers

The pulverizers selected for this contract are Babcock Borsig Power, Inc.’s ATRITA®Pulverizers, shown in Figure 3.3. ATRITA® Pulverizers are simply designed and ruggedlyconstructed for minimal, easy maintenance. All moving parts rotate on a single shaft held inplace by two bearings mounted externally on separate bearing pedestals. Tramp materialsare rejected to prevent damage to pulverizer parts.

The original contract required that full boiler load be attainable with two of the threepulverizers in service. Because of the low HGI of the El Cerrejon coal, the third pulverizerhad to be brought into service in order to achieve the predicted fineness of 70% through 200mesh and 98% through 50 mesh. (50 mesh fineness of > 98% was never a problem even withtwo-mill operation.)

The boiler’s guaranteed auxiliary power was also met under these conditions. As statedin the burner section, the coal was very wet at times. There were instances during the earlyperiod of start-up when the coal was nearly in the form of slurry.

12

The three mill operation, although necessary because of the coal’s low HGI (often in thehigh 30’s as compared to the specification minimum of 50), was also very helpful during wetcoal periods. As mill load is reduced, the primary air to coal ratio increases, improving thedrying capability of the milling system. For instance, starting with a primary air to coal ratioof 1.3 at full mill load results in a 1.75 ratio at 2/3 mill load. This increase in primary air-flow occurs when three mills are used instead of two. Assuming a constant primary air tem-perature under both sets of conditions, the drying capability of the milling system increasesdirectly as the change in primary air to coal ratio. In this case, it is 1.75/1.3 or approximately35% more drying energy with three mill operation assuming the same PA temperature fortwo- or three-mill operation.

Since the coal was more difficult to grind than had been anticipated, additional analyseswere performed to determine the cause. First, Babcock Borsig Power, Inc. analyzed the pul-verized coal leaving the ATRITA® Pulverizers and found the moisture to be in the range of5 to 6%, typically. Secondly, since this is a non-US coal it was decided to analyze the coal forHGI versus moisture, which is not normally considered for coals with bituminous ashes.Interestingly, the HGI decreased significantly as the moisture was increased from a sampleprepared and dried per ASTM D409 to about 5 % moisture and then the HGI rose to a levelslightly higher than the ASTM D409 prepared sample at 10 % moisture (refer to Figure 3.4).The low point of the curve is coincident with the moisture content of the coal leaving themills as well as with the moisture content of the coal in the grinding zone of the ATRITA®Pulverizer where a large percentage of the pulverizing energy is consumed. The 10 pointdrop in HGI shown reduces the pulverizer capacity by about 10%. This has a significant

Figure 3.3 ATRITA® Pulverizer

13

impact on fineness and power at the originally designed full mill load condition. This infor-mation confirmed the need for three-mill operation at full boiler load to ensure that thedesign fineness is achieved. If the 200 mesh fineness is allowed to degrade to about 65%through 200 mesh, two mills are still able to carry full load as long as the total as receivedmoisture of the coal is less than 12.5%.

Figure 3.4 Hardgrove Grindability Index vs Total Moisture

3.4 Coal Pile Management

Extremely wet coal with a moisture content well above the maximum design value of20% is a major problem at this site due to heavy rains during certain times of the year. Thisis apparent when water is observed running off the coal transport belts draining from thebottom of the in-plant storage. During wet periods of initial operation the total coal moisturewas greater, more than 30–35%. Since the inherent coal moisture is approximately 2 per-cent, this means the surface moisture was over 30%. Surface moisture levels greater than30-35% exceeded the pulverizer drying capability, resulting in boiler load limitations.

Black & Veatch and Babcock Borsig Power, Inc. worked with the owner to establish waysof configuring and compacting the coal pile to permit water to drain from the pile. The coalpile, properly compacted and configured, will drain water away from the reclaim area andminimize surface moisture. Under periods of heavy rain, the coal can then be reclaimed fromthe portions of the coal storage area which have had an opportunity to drain. The owner isalso considering some form of roofing over the reclaim portion of the coal pile to further min-imize this problem.

4.0 TESTING AND RESULTS

During the performance tests, test conditions differed from the values associated withthe plant guarantee basis. Corrections to boiler efficiency and auxiliary power consumptionwere made to account for these deviations so a true comparison to guaranteed values couldbe made.

Boiler test procedures were developed based on the ASME Performance Test Codes PTC4.1 (1991) and PTC 4 (1998) to determine if the actual boiler efficiency and auxiliary powerconsumption were within the guarantees. Testing consisted of two four-hour test runs.

14

When calculating boiler efficiency, the PTC 4.1 code includes the following correction cal-culations when the as-fired test conditions differ from design conditions:

1. Reference Temperature

2. Undiluted gas temperature leaving the air heater (air heater leakage)

3. Fuel Constituents

4. Fuel HHV

The Code also allows for mutually agreed upon secondary corrections when the test fuelis different than the coal for which the performance guarantees are based (refer to PTC 4.1;3.01.15 and PTC 4; 3.2.3). Table 4.0 lists the appropriate set of additional correction curvesdeveloped for evaluation of the boiler efficiency and auxiliary power guarantee values. Thecurves themselves are shown at the end of this section.

Table 4.0 Correction Curves for Boiler Performance

Figure 4.1 Boiler ash loss on ignition (LOI) adjustment as a function of fueland ash content

Figure 4.2 Air heater flue gas exit temperature adjustment as a function of fuelmoisture

Figure 4.3 Effective design mill capacity as a function of tested coalHardgrove Index (HGI)

Figure 4.4 Effective design mill capacity as a function of tested fuel moisture

Figure 4.5 Total pulverizer power as a function of effective design coal burned(coal flowrate)

Use manufacturer’s Forced draft fan power as a function of combustion air flowratefan curve

Use manufacturer’s Induced draft fan power as a function of flue gas flowratefan curve

4.1 Boiler Efficiency and Auxiliary Power Calculations

The following sections 4.1.1 and 4.1.2 review the procedure used to calculate boiler effi-ciency and auxiliary power consumption

4.1.1 Boiler Efficiency

The procedure to adjust boiler efficiency for the as-fired fuel and the ambient conditionsis described below.

The predicted boiler efficiency is the manufacturer’s design efficiency, adjusted for actu-al test conditions that differ from the guarantee basis. The adjusted for actual test conditionsboiler efficiency shall be determined by the following equation:

15

Equation 4.1: ηBA = (ηBD) x (ηBT / ηBP)

where:ηBA = Adjusted boiler efficiency, %.ηBT = As-Tested boiler efficiency, %.ηBD = Design boiler efficiency, %.ηBP = Predicted boiler efficiency with the as tested coal, %.

The original design boiler performance associated with the design fuel, ambient condi-tion, and heat load is as follows:

Boiler Efficiency (based on ASME PTC 4.1)

• Dry Flue Gas Loss, % 4.33• Moisture (Liquid in Fuel), % 0.79• Water (from combustion of hydrogen), % 3.26• Unburned Carbon Loss, % 1.24• Radiation Loss, % 0.25• Unaccountable Loss

(includes loss due to moisture in the air), % 0.50• Manufacturer’s Loss, % 1.00• Total Loss, % 11.37• Boiler Efficiency (gross basis) 88.63

Boiler Design Conditions

• Fuel Burn Rate, lbm/h 109,509• Total Heat in Fuel, 106 Btu/h 1,242.9• Total Heat Absorbed by Fluids, 106 Btu/h 1,114.1• Total Combustion Air, lbm/h 1,158,268• Total Flue Gas Flow, lbm/h 1,250,252• Excess Air, % 20• Flue Gas Temperature entering A.H., °F 63• Flue Gas Temperature leaving A.H., °F 286

Ambient Conditions

• Dry Bulb Temperature,°F 95• Wet Bulb Temperature, °F 80

As noted above, actual test conditions were different from design conditions. The pre-dicted boiler performance for use in Equation 4.1 was determined as described in the proce-dure below:

1. Rerun boiler performance with the “as-fired” fuel holding the heat absorbed bythe fluids and air heater flue gas exit temperature (FGET) constant.

2. Adjust boiler performance for ambient conditions, assuming a constant air heaterefficiency in accordance with ASME PTC 4.1.

3. Adjust LOI based on fuel and ash type as provided in correction curve shown inFigure 4.1. Recalculate boiler performance.

16

4. Adjustment for Air Heater (AH) Flue Gas Exit Temperature (FGET). Adjust AHFGET to flue gas flow using flue gas from Step 2. Use correction curve shown inFigure 4.2.

5. Recalculate and iterate boiler performance with adjusted FGET. Repeat to getηBP. Calculate fuel burn rate (mFBRE), total combustion air (mCAE), and total flue-gas flow (mFGE).

4.1.2 Auxiliary Power Consumption

The boiler auxiliary power consumption was adjusted to the Project Guarantee Basis asfollows:

∆PAUX = ∆PPULV +∆PFD + ∆PID

where:

∆PAUX = Adjustments to auxiliary power due to fuel, kW.

∆PPULV = Adjustments to pulverizer power due to fuel impact on fuel flow and HGI, kW.

∆PFD = Adjustment in combustion air (FD Fan power) due to fuel, kW.

∆PID = Adjustment to flue gas flow (ID Fan power) due to fuel, kW.

As discussed in the section for boiler efficiency, changes in fuel characteristics result inchanges in fuel burn rates, Hardgrove Grindability Index (HGI), combustion air flow, pul-verizer power, flue gas flow, and flue gas exit temperature.

As the coal HGI increases, the coal mill is effectively pulverizing more of the design coal.Figure 4.3 shows a graph of the effective design coal factor as a function of HGI. As coal topulverizer increases the mill power consumption increases until it becomes fully loaded. Atthat time, an additional pulverizer is required and a step change in auxiliary power is real-ized. Figure 4.5 shows incremental pulverizer power as a function of effective design coalburned. The procedure to calculate ∆PPULV is as follows:

Obtain expected fuel burn rate with test coal = mBRE .

From test coal HGI, Figure 4.3, determine effective design coal factor = EDCF1.

From the coal moisture, Figure 4.4, determine effective coal factor = EDCF2.

Determine total capacity coal flow from the following:

FBRcapacity = mFBRE / (EDCF1 x EDCF2)

Determine number of mills (2 or 3) required in operation due to fuel type, moisture andHGI. If FBRcapacity > 128,340 lb/h of 75 HGI coal, three mills must be used due to fuel quali-ty.

From Figure 4.5, Equivalent FBR and number of predicted mills operating, determine∆PPULV.

The procedure to calculate the adjustment for FD Fan Power, ∆PFD, is as follows:

1. Obtain expected combustion air with test coal = mCAE .

2. From the manufacturer’s fan curve and mCAE determine ∆PFD .

17

Similarly, the procedure to calculate the adjustment for ID Fan Power, ∆PID is as follows:

1. Obtain expected flue gas flow with test coal = mFGE .

2. From the manufacturer’s fan curve and mFGE determine ∆PID. It is noted that thisfactor is based on the expected change in flue gas air heater exit temperature.

4.2 Test Results

Description Test 1 Test 2 Guarantee ∆2/2/00 2/2/00

Steam Flow, pph 1,079,441 1,079,466 1,104,310 metNet Electrical Output, kW 123,150 123,073Gross Electrical Output, kW 132,467 135,931Gross Reactive Power, kVAR 41,624 42,518Steam to SJAE Flowrate

(design value), lb/hr 660 660Coal Carbon, mass % 68.58 66.16Coal Hydrogen, mass % 4.57 4.33Coal Nitrogen, mass % 1.38 1.29Coal Oxygen, mass % 8.38 7.92Coal Moisture, mass % 11.47 14.56Coal Sulfur, mass % 0.66 0.55Coal Ash, mass % 4.96 5.19Coal HHV, Btu/lb (at const pressure) 12,060 11,596Test Carbon loss % 2.19 2.4Predicted Carbon loss % 2.56 2.57Test Boiler Efficiency, % 87.10 86.44Predicted Boiler Efficiency 86.34 85.82Adjusted Boiler Efficiency, % 89.41 89.27 88.63 +.72, metHGI, none 45 46Air Heater Gas Exit Temperature, °F 312.2 308.2Flue Gas Oxygen Content, % 3.68 3.86Test Auxiliary Power Consumption, kW 2,284 2,286Auxiliary Power

Consumption Adjustments, kW 86 459Adjusted Auxiliary

Power Consumption, kW 2,198 1,827 2155 -143Superheat Final Temperature, °F 1006 1006 1005 metSuperheat Outlet Pressure, psig 1946 1946 1965 metEconomizer Water Side

Pressure Drop, psi 47 46 50 metSuperheater Steam Side

Pressure Drop, psi 100 110 150 metNOx Emissions, lbs/106 Btu 0.46 0.46 0.53 -0.07, met

Table 4.2 Test Results

18

The Acceptance Test results are shown in Table 4.2.

Special care was taken to ensure represented fly ash samples were taken and accurateunburned carbon results obtained. The El Cerrejon fly ash exhibited non-homogenous char-acteristics with the unburned carbon having the tendency of separating from the ash.Special procedures beyond the requirements of ASTM D5373 or D3172 were employed byindependent laboratories (including grinding to smaller size particles) in order to get repeat-able and accurate unburned carbon results.

4.3 Test Summary

Procedures were developed to adjust the test results back to the project guarantee basisso that comparisons to project guarantees could be made. Adjustments for fuel and ash werenoticeable due to the deviation between the El Cerrejon coal and the design coal. The steamgenerator exceeded its performance guarantees.

Figure 4.1 Boiler LOI Adjustment vs Fuel and Ash Content(Y axis values are proprietary)

Figure 4.2 Air Heater Flue Gas Outlet Temperature vs Fuel Moisture(Y axis values are proprietary)

19

Figure 4.3 Effective Design Mill Capacity vs Tested Coal Hardgrove Grindability Index(Y axis values are proprietary)

Figure 4.4 Effective Mill Capacity vs Tested Fuel Moisture(Y axis values are proprietary)

Figure 4.5 Total Pulverizer Power vs Effective Design Coal Burned(Y axis values are proprietary)

Hardgrove

The data contained herein is solely for your information and is not offered,or to be construed, as a warranty or contractual responsibility.