A paper in the proceedings of a conference on fluidization 11 16–17 November 2011, Johannesburg, South Africa

IFSA 2011, Industrial Fluidization South Africa: 11–29. Edited by A. Luckos & P. den Hoed Johannesburg: Southern African Institute of Mining and Metallurgy, 2011

Kuyasa mine-mouth coal-fired power project: Evaluation of circulating fluidized-bed

technology

T. Aziz and M.H. Dittus Black & Veatch Corporation, Overland Park, Kansas, USA

Keywords: fluidized bed, pulverized coal, technology evaluation, discard coal, dolomite, limestone, conceptual design

Abstract—Kuyasa Mining (Pty) Ltd. of South Africa (Kuyasa) is planning to develop a multi-phased mine-mouth coal-fired power project with a total generating capacity of 2,400 MW (gross). The plant will be located close to Kuyasa Delmas and Ikhwezi coal mines in Mpumalanga Province, South Africa. The proposed fuel is a low-quality coal with low calorific value and high ash content. The paper evaluates suitable boiler technology and provides conceptual design for the first phase of the proposed project development, which is planned to be 4×150 MW (gross). The paper further addresses the advantages and challenges of circulating fluidized bed (CFB) technology to power generation projects.

Evaluation of the boiler technology compares CFB with pulverized coal (PC) boiler in terms of each boiler’s technical characteristics and operating behaviour, which include fuel flexibility, flue gas emissions, water requirement for scrubber/desulfurization, auxiliary power consumption, solid waste production and maintenance requirements. Based on the evaluation, the CFB boiler has been selected as a suitable technology for the proposed project. One of the key technical advantages of the CFB boiler is its flexibility in burning solid fuels of varying quality, especially low-quality solid fuels, without sacrificing boiler performance relative to a PC boiler. In addition, significant advances in CFB-boiler technology and its prospects in South Africa are also discussed.

Being one of the pioneers in using the CFB technology in South African power generation, the Kuyasa power plant will comprise four units of single, subcritical, reheat CFB boilers. Sulfur dioxide (SO2) emissions will be controlled by injecting sorbent in the combustion chamber. A pulse jet fabric filter system will be used to control particulate emissions. Each unit will be equipped with a 150-MW condensing steam turbine. Units will be equipped with a condensate polishing system. Cycle heat rejection will be accomplished using air-cooled condensers and fin-fan coolers for auxiliary cooling. The plant will be designed as a zero liquid-effluent-discharge facility.

INTRODUCTION With increasing electrical demand, reliability of the South African electrical grid has been challenged, and in the absence of new power generation capacity additions, scheduled load shedding, brownouts, and blackouts have occurred in South Africa. A similar trend in electrical demand shortfalls is observed in countries neighbouring South Africa that share and wheel power through the Southern African Power Pool (SAPP). These shortfalls are expected to continue in the immediate future as the SAPP-participating countries are not expected to add new power generation resources immediately.

In an effort to mitigate electrical shortfall, the South African government, in 2008, directed Eskom to invite the private sector to construct power plants on a Build, Own and Operate (BOO) basis for the exclusive sale of electrical power to Eskom. Through a Request for Qualification (RFQ), Eskom had invited interested South African Independent Power Producers (IPPs) to participate in the construction of new power plants either under Medium-Term Power

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Purchase Programmes (MTPPP) or on Base-Load IPP Programmes. Projects that can be fully operational by mid-2012 are considered under MTPPP, whereas any base-load plant being commissioned between 2013and 2016 is considered under the Base-Load IPP Programme.

Kuyasa has proposed developing a multi-phased, mine-mouth, coal-fired power project with a total generating capacity of 2,400 MW (gross). The first phase of this proposed project will be the development of a 600 MW (gross) power plant project, which will be constructed on a site located approximately 80 km east of Johannesburg and about 20 km southeast of Delmas. The proposed project will be fuelled by low-quality coal produced by Kuyasa’s Delmas Coal Mine. The proposed project will employ commercially available fluidized-bed-boiler technology capable of burning low-quality coal or discard coal without sacrificing boiler performance.

The 600 MW (gross) power plant configuration will consist of four units each capable of producing 150 MW (gross) electrical power. Each unit will consist of one circulating fluidized bed (CFB) boiler supplying steam to a 150 MW (gross) steam turbine generator (STG). In addition, the unit will also include all associated material handling systems for coal, sorbent, and ash, as well as all other auxiliary systems. Emissions resulting from the combustion of coal will be controlled to remain within the proposed South African emissions limits. The facility will use air c-ooled condensers (ACCs), fin-fan coolers, and a zero-liquid discharge (ZLD) system to minimize water wastage and avoid any discharge of wastewater from the power plant boundary limits.

The proposed power plant will be a pioneer project in South Africa utilizing low-quality coal or discard coal as a potential fuel source for electricity generation. South Africa has accumulated over a billion tonnes of discard coal generated from its coal beneficiation processes.1 .The discard coal has largely not been utilized owing to the variability of its quality along with its low calorific value, high ash and sulfur contents. The disposal of discard coal poses environmental challenges for the mine owners and operators as environmental regulations are becoming more and more stringent. Employing commercially available fluidized-bed boiler technology would provide an opportunity for new power plants to utilize discard coal as a potential fuel source for electricity production and at the same time reducing its environmental challenges for safe disposal. Discard coal could also offer low delivered cost fuel for mine-mouth power plants.

In this paper, overviews of the need for power and the availability and quality of discard coal as a potential fuel source for electricity generation in South Africa are presented. The availability and quality of sorbent, which is typically used in fluidized-bed boilers to control sulfur dioxide (SO2) emission, is also discussed. In addition, the paper also provides boiler technology evaluation and a conceptual design for the proposed project development. Furthermore, the advantages and challenges that CFB technology bring to power generation projects are also discussed in the paper.

NEED FOR POWER As a result of accelerated economic growth and higher-than-expected electrical demand in South Africa, coupled with the fact that no new generation was added for a number of years, Eskom’s electrical grid has been challenged to support its consumers reliably. Eskom has been forced to curtail load, resulting in scheduled and at times unscheduled load shedding, brownouts, and blackouts. According to the Eskom Integrated Report 2011, its capacity reserve margin is currently at 14.9%.2 This is lower than the 19% reserve margin recommended in the National Energy Regulator of South Africa (NERSA) Third National Integrated Resource Plan (NIRP3) to meet reliability and economics standards for South Africa.3.Currently, peak demand in South Africa is at 36,664 MW and it is projected, by NERSA NIRP3, to grow at an annual rate of 4.2% through 2026.2, 3

Eskom’s available generation capacity is at 40,483 MW as of April 2009.4 Eskom also plans to decommission some of its older, less-efficient units in the future as more efficient units are placed online. The decommissioning of these units will reduce the overall capacity of the grid. It is estimated that a total of approximately 1,100 MW will be decommissioned by 2013 to 2014 and a total of 10,332 MW by 2026.5

In an effort to mitigate the capacity constraints, Eskom has launched a Demand Side Management (DSM) programme to sustain 3,000 MW reduction until 2012.5 The power

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reduction programme includes a 10% voluntary curtailment of power to large consumers and pre-emptive load shedding. Eskom has also initiated the return to service of a number of mothballed units and a new build programme involving an aggressive construction of new power generating facilities by 2016. Total capacity addition for the return to service and the new build programme is about 16,304 MW.6

Owing to large expansion projects, the funding requirements and expeditious schedule of the proposed projects has exerted stress on the financial sustainability of Eskom and on Eskom’s ratepayers. Consequently, in January 2008, the South African government asked Eskom to initiate an IPP programme to aid Eskom in the aggressive ramp-up of power, to relieve financial stress on Eskom, and to re-establish an adequate reserve margin.

Despite Eskom’s effort to mitigate the capacity shortfall, South Africa is still expected to experience capacity constraints. Taking into consideration current generation, planned capacity additions, the 3,000 MW DSM reductions, and a medium electrical demand growth rate of 4.2% with 19% reserve margin, as determined by NERSA; South Africa is expected to experience capacity shortfalls in excess of 6,000 MW in the year 2014. Even if Eskom’s DSM plan to sustain a 3,000 MW load reduction is carried through to 2016 instead of the planned 2012, a capacity shortfall in excess of 5,000 MW for the required 19% reserve margin can be expected. These capacity shortfall projections are illustrated in Figures 1 and 2.

Although Eskom’s planned or potential capacity addition projects beyond 2016 have not publicly been announced as yet, Figure 3 provides an extended forecast from 2016 to 2025. It assumes no additional Eskom units are added after 2016. The forecast suggests that South Africa would require additional capacity in excess of 45,000 MW by 2025 to sustain a projected economic growth and reliable electric grid with a 19% reserve margin.

In light of the expected Eskom-dependent capacity shortfalls, the assessment suggests that Eskom will require additional support from the SAPP-participating countries or from IPPs to sustain a reliable electrical grid. Other interconnected SAPP countries have also proposed potential capacity-addition projects that may aid in alleviating capacity constraints in South Africa; however, according to the SAPP, none of these projects has yet secured the required funding to support the construction of these projects. Under this scenario, IPP projects, such as the Kuyasa power project, will play a crucial role in providing the needed capacity additions in South Africa.

DISCARD-COAL AVAILABILITY AND QUALITY South Africa is one of the major producers and exporters of coal. In 2009, South Africa produced about 247 million tonnes of coal and exported about 67 million tonnes.1 Coal beneficiation or washing of coal is typically done to achieve export coal quality requirements. These processes have generated significant quantities of discard coal of about 60 million tonnes annually.1 An estimated total accumulated amount of over one billion tonnes of discard coal is currently available in South Africa.1 By 2020, it is estimated that the total accumulated amount could reach about 2 billion tonnes.8

In 2001, a survey was commissioned by the South Africa Department of Minerals and Energy to provide an inventory of discard coal generated within the country. The results of this survey, on a tonnage basis, illustrated variable quality of discard coal with low calorific value, high ash and high sulfur contents, as shown in figures 4–6.9

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Figure 3. Forecasted capacity shortfalls without Eskom capacity additions beyond 2016

Figure 4. Discard-coal calorific value distribution

(Source: Dept. of Minerals and Energy, Republic of South Africa. National Inventory Discard and Duff Coal. 2001 Summary Report)

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Figure 5. Discard coal ash-content distribution

(Source: Dept. of Minerals and Energy, Republic of South Africa. National Inventory Discard and Duff Coal. 2001 Summary Report)

Figure 6. Discard-coal sulfur-content distribution

(Source: Dept. of Minerals and Energy, Republic of South Africa. National Inventory Discard and Duff Coal. 2001 Summary Report)

From Figure 4, it is estimated that about 70% of the discard coal included in the survey has a calorific value distribution of 11–17 MJ/kg and about 6% has a calorific value distribution of 20 MJ/kg and higher. About half of the discard coal included in the survey has an ash-content distribution of 40–50% while about 26% has an ash-content distribution higher than 50%, as shown in Figure 5. In terms of its sulfur content, about 40% of the discard coal included in the survey has a distribution of 2–3% sulfur content and about 30% has a sulfur content distribution of higher than 3%, as illustrated in Figure 6.

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The discard coal has not been largely utilized and its disposal poses environmental challenges for the mine owners and operators even as its disposal methods have evolved over time. This is because environmental regulation governing the disposal of discard coal is becoming more and more stringent. The fluidized-bed-boiler technology is commercially available with a proven capability of burning discard coal without sacrificing boiler performance. By employing the fluidized-bed-boiler technology, power plants can utilize discard coal as a potential fuel source for electricity generation and at the same time solve the problem of coal disposition. With over a billion tonnes of discard coal currently estimated to be available in South Africa, at least about 6,000 MW of electricity could potentially be generated by using this fuel source assuming an average annual capacity factor of 85% and plant economic life of 30 years.

The proposed Kuyasa mine-mouth, 600-MW (gross), coal-fired power plant is a pioneer project in South Africa employing fluidized-bed-boiler technology for burning low-quality coal. The low-quality coal will be supplied from the Kuyasa’s Delmas Coal Mine with the following design, as-received, characteristics based on No. 4 Upper Seam coal average qualities:

• Gross calorific value (HHV) ........................ 16.3 MJ/kg • Carbon ............................................................ 40.20% • Hydrogen ......................................................... 2.54% • Nitrogen............................................................ 1.44% • Oxygen.............................................................. 6.19% • Sulfur................................................................. 1.50% • Moisture............................................................ 7.90% • Ash .................................................................. 40.23% Based on the preceding fuel characteristics, the project is estimated to consume about

2.8 million tonnes of coal a year or 84 million tonnes of coal for a 30-year economic plant life.

SORBENT AVAILABILITY AND QUALITY A sorbent such as limestone or dolomite is used for flue-gas desulfurization (FGD) or to control SO2 emissions to the required emissions limit. In a fluidized-bed boiler, the sorbent is injected directly into the combustion zone where chemical reactions associated with the sorbent and fuel reduce SO2 emissions. The actual amount of sorbent required will depend upon the amount of sulfur contained in the fuel, the reactivity of the sorbent (CaCO3 content), the temperature of combustion, and the amount of fuel consumed. Limestone is generally classified as calcite minerals with CaCO3 content greater than 80%, whereas dolomite typically comprises 35 to 55% CaCO3. The selection of a sorbent is consumer specific and is typically driven by the availability and economics associated with its use and site specific constraints.

South Africa has extensive carbonate deposits with a calculated reserve base of approximately 2.17 billion tonnes (2005 basis) located in the major deposits shown in Figure 7.10 The largest limestone resources are located within a relatively narrow, 150-km-long belt along the Northern Cape boundary, while the largest economically viable dolomite resources are located in the Western Cape’s Piketberg-Vredendal-Swellendam district and Gauteng’s Pretoria-Lyttleton-Meyerton area.10 South Africa’s limestone and dolomite industry comprises 24 groups or controlling companies and 41 quarries. There are 27 limestone quarries, 10 dolomite quarries, and 4 operations mining both limestone and dolomite.10

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Figure 7. Major limestone and dolomite deposits in South Africa (Source: Agnello, V.N. 2005. Dolomite and limestone in South Africa: Supply and demand 2005.

Department of Minerals and Energy, Republic of South Africa. Report R49/2005)

Based on a 400 mg/Nm3 SO2 emission limit and coal sulfur content in excess of 1.5%, the proposed Kuyasa power plant may require external FGD system to supplement the fluidized-bed-boiler in reducing SO2 emission to allowable limits. The external FGD system utilizes lime and recycled fly ash as a sorbent.

South African limestone has CaCO3 content in the range of 85–95% while its dolomites have CaCO3 content in the range of 35–55%. Based on the lower and higher contents of CaCO3 in the dolomite considered for the project, and an assumed 85% capacity factor, the proposed project will require, respectively, approximately 33 million tonnes and 21 million tonnes of dolomite over a 30 year project life. Similarly, based on the lower and higher contents of CaCO3 in limestone, the proposed project will require, respectively, approximately 13 million tonnes and 12 million tonnes of limestone over a 30 year project life. Figure 8 illustrates the sorbent requirements for a 600 MW CFB power plant at various capacity factors and CaCO3 contents.

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Figure 8. Estimated annual sorbent requirements for a 600 MW (gross) CFB power plant

STEAM-GENERATOR TECHNOLOGY The function of the steam generator is to provide controlled release of heat in the fuel and efficient transfer of heat to the feedwater and steam. The transfer of heat produces main steam at the pressure and temperature required by the high-pressure steam turbine. Heat is also transferred through the reheater to increase the temperature of the high-pressure steam turbine exhaust, or cold reheat steam, to the conditions required by the intermediate-pressure turbine.

Conventional coal-fired steam generator design for high pressure reheat boiler applications has evolved into two basic combustion and heat transfer technologies. Suspension firing of pulverized coal (PC) and fluidized-bed combustion of crushed coal are the predominant technologies in use today. The characteristics of these alternative technologies are addressed below.

Pulverized-coal steam-generator technology With PC technology, coal that is sized to roughly 20 mm top size is fed to the pulverizers, which finely grind the coal to a size of no less than 70% passing through a 200 mesh screen (70 µm). This pulverized coal is conveyed to the coal burners suspended in the primary air stream. At the burner, this mixture of primary air and coal is further mixed with secondary air and with the presence of sufficient heat for ignition. The coal burns in suspension with the expectation that combustion will be complete before the burner flame contacts the back wall and side walls of the furnace. Current PC combustion technology also includes features to minimize unintended products of combustion, such as oxides of nitrogen (NOx), and other toxics gases such as carbon monoxide (CO).

Owing to the high combustion temperature of pulverized coal at the burners, the furnace enclosure is constructed of membrane waterwalls to absorb the radiant heat of combustion. This heat absorption in the furnace is used to evaporate the preheated boiler feedwater that is circulated through the membrane furnace walls. The steam from the evaporated feedwater is separated from the liquid feedwater and routed to additional heat transfer surfaces in the steam generator. Once the products of coal combustion (ash and flue gas) have been cooled sufficiently by the waterwall surfaces, so that ash is no longer molten but in solid form, heat transfer surfaces predominantly of the convective heat transfer type are utilized to absorb the remaining heat of combustion. These convective heat transfer surfaces are the superheaters, reheaters, and economizers, located within the steam generator enclosure downstream of the

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furnace section. The final section of heat recovery is in the air preheater, where the flue gas leaving the economizer surface section of the steam generator is further cooled by regenerative or recuperative heat transfer to the incoming combustion air. A typical sub-critical PC boiler arrangement is illustrated in Figure 9, and schematically in Figure 10.

Figure 9. Typical sub-critical PC boiler

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Figure 10. Typical schematic of sub-critical PC boiler

Fluidized-bed, coal-combustion, steam-generation technology During the 1980s, fluidized-bed combustion (FBC) rapidly emerged as a viable alternative to pulverized coal-fuelled units for the combustion of solid fuels. Initially used in the chemical and process industries, FBC was applied to the electric-utility industry because of its perceived advantages over competing combustion technologies. SO2 emissions could be controlled from FBC units without the use of external scrubbers, and NOx emissions from FBC units were inherently low because of lower combustion temperatures. Furthermore, FBC units were touted as being “fuel flexible”, with the capability of firing a wide range of solid fuels with varying heating value, ash content and moisture content. Also, slagging and fouling tendencies were minimized in FBC units because of low combustion temperatures.

By 1991, the transition had been made from small industrial-sized boilers to several electrical utility reheat boilers in operation in the size range from 100 to 165 MW. Currently, several reheat boilers are in service supporting electrical generation up to 300 MW, and boiler suppliers are offering boiler designs to provide steam generation sufficient to support in excess of 550 MW with full commercial guarantees. Fuels for these applications range from petroleum coke and bituminous coal to high-ash refuse from bituminous coal preparation and cleaning plants and high moisture fuels such as lignite.

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In FBC, the combustion temperature is controlled to approximately 840–870°C (1,550–1,600 F), which compares with approximately 1,650°C (3000°F) for conventional PC boilers. Combustion at the lower temperature has several benefits; first, the lower temperature minimizes sorbent requirements because the required Ca-S molar ratio for a given SO2 removal efficiency is minimized in this temperature range. Secondly, 870°C (1,600°F) is well below the ash-fusion temperature of most fuels, so the fuel ash never reaches its softening or melting points. The slagging and fouling problems that are characteristic of PC units are significantly reduced, if not eliminated. Finally, the lower temperature reduces NOx emissions.

Since combustion temperatures are below ash fusion temperatures, design of an FBC boiler is not as dependent on ash properties as is conventional a PC boiler. With proper design considerations, an FBC boiler can fire a wider range of fuels with less operating difficulty.

The most common type of FBC in the utility industry is the CFB. A typical arrangement is illustrated schematically in Figure 11.

Figure 11. A typical CFB boiler

In a CFB, primary air is introduced into the lower portion of the combustion chamber, where

the heavy bed material is fluidized and retained. The upper portion of the combustor contains the less dense material that is entrained with the flue gas from the bed. Secondary air is typically introduced at higher levels in the combustor to ensure complete combustion and to reduce NOx emissions. The combustion gas generated in the combustor flows upward with a considerable portion of the solids inventory entrained. These entrained solids are separated from the combustion gas in hot cyclone-type dust collectors or in mechanical particulate separators, and are continuously returned to the combustion chamber by a recycle loop. The

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cyclone separator and recycle loop may include additional heat recovery surface to control bed temperature and steam temperature and to minimize refractory requirements.

The combustion chamber of a CFB unit generally consists of membrane-type welded waterwalls to provide most of the evaporative boiler surface. Heat transfer to evaporative surfaces is primarily by convection and conduction from the bed material that contacts the evaporative wall surfaces or division panel surfaces located in the upper combustor. The lower third of the combustor is refractory lined to protect the waterwalls from erosion in the high-velocity dense bed region.

The fuel size for a CFB boiler is much coarser than the pulverized coal needed for suspension firing in a PC boiler. Compared with the typical 70-µm particle size for a PC unit, the typical fuel size for a CFB is approximately 5 mm. Especially for high-ash fuels, the use of larger fuel sizing reduces auxiliary power requirements and pulverizer maintenance requirements; it also eliminates the high cost of pulverizer installation.

Ash removal from a CFB boiler is from the bottom of the combustor and also from fly ash that is entrained in the flue-gas stream as in PC boilers. With a CFB boiler the ash split between bottom ash and fly ash is roughly 50-50 bed ash to fly ash. All of the ash drains from CFB boilers are typically retained in a dry condition without the need for water-impounded hoppers or water-submerged conveyors typically utilized for PC boiler bottom-ash collection and conveying.

TECHNICAL CHARACTERISTICS OF CFB VERSUS PC In addition to addressing the technical characteristics of the two competing boiler technologies, we also consider other characteristics, which are also summarized in the following sections.

Environmental Environmental impacts are categorized as flue gas emissions, solid waste production, and water consumption.

Flue-gas emissions The flue gas emissions include fly-ash particulates, SO2, NOx, and CO. As a larger portion of the fuel ash will leave a CFB boiler with bed ash, a lower total fly-ash-particulate loading will exist in the flue gas entering the particulate removal equipment. Depending on the type of particulate removal device, this would lead to a lower particulate emission rate for a CFB boiler. The addition of a supplemental sorbent with the fuel in a CFB boiler will result in lower SO2 emissions with the CFB technology. The lower combustion temperatures of the CFB boiler will result in a significant reduction in NOx emissions from a CFB boiler compared with a PC boiler. CO emissions for the two technologies will be very similar. Both can be operated with very high combustion efficiencies to minimize CO emissions.

Solid-waste production Solid-waste production for the two technologies will be similar with the exception that the bottom ash from the PC boiler would be transported in a wetted condition because of the bottom-ash collection technology that includes either water impounded bottom-ash hoppers or submerged conveyors below the furnace throat. Bed-ash extraction from a CFB is a dry process where the ash is collected in a granular form and cooled with a combination of fluidizing cooling air and water-jacketed screw coolers.

Boiler-water consumption Water consumption for the two technologies would be essentially identical for boiler drum blowdown to maintain boiler water quality. However, in the case of the use of steam for sootblowing uses, the boiler water makeup requirements may be slightly higher owing to the higher sootblowing steam demand of PC-boiler technology. As water uses for ash transport would also be less for CFB applications, the total service water demand would also be lower for CFB applications. CFB boilers are capable of operating within the SO2 emission limits when the sulfur content in the fuel coal (with the specific Delmas Coal characteristics) is limited to approximately 1.5%. Up to this value, the CFB boiler would have an advantage over the PC

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boiler relative to water consumption for SO2 treatment as no external FGD systems would be required. Should this value be exceeded, however, an external FGD system may be required and the water consumption advantage would be cancelled.

Operation Operational impacts are categorized as auxiliary power, maintenance, fuel flexibility, and start-up and load ramping.

Auxiliary power The primary air fans of the CFB boiler provide the motive power to fluidize and to circulate the bed material. Thus, these fans have a higher power requirement than that of the primary air fans for a PC boiler application. However, since the CFB boilers do not need pulverizers, this normally results in the auxiliary power requirements for the two technologies to be relatively similar. In the case of high-ash fuels that result in higher pulverizing energy requirements and where the use of CFB boiler technology precludes the need for an SO2 scrubber, the auxiliary power demand of the CFB boiler technology is typically lower than that of a PC boiler-scrubber combination.

Maintenance The major maintenance requirements of CFB boilers are refractory repairs due to the erosive effects of the bed materials circulating through the boiler components. Initial CFB boiler applications experienced significant refractory maintenance requirements. Subsequent refractory system improvements, materials and installation techniques have provided significant reductions in these maintenance requirements. The major maintenance requirements of PC boilers and their auxiliaries are often associated with pulverizers, sootblowers, and associated heat transfer surface damage caused by sootblowing erosion in areas where excessive sootblowing is needed to prevent accumulation of agglomerating ash deposits. CFB boilers will not have pulverizers and will have significantly fewer sootblowers since the coal ash temperature is not elevated to the point where it becomes molten or agglomerating. In the case of high-ash fuels where pulverizer and sootblower duty is extreme, the total maintenance requirements of CFB boilers would be expected to be less than those of a PC boiler and its auxiliaries.

Fuel flexibility CFB boilers have the capability for superior fuel flexibility compared to PC boilers. Since the combustion temperature of CFB boilers is below the ash initial deformation temperature, the slagging and fouling characteristics of alternative fuels are not a concern. As long as the CFB boiler auxiliaries such as fuel feed equipment and ash removal equipment are provided with sufficient capacity, a very wide range of fuel heating values and ash content can be utilized. In cases where FGD is also carried out in the CFB boiler, the capacity of the sorbent feed equipment also needs to be designed for the range of fuel sulfur content that is expected to occur. Owing to the long fuel residence time in the CFB boiler combustion loop, a very wide range of fuel volatile matter content can also be utilized. Fuel volatility ranges well below that needed to burn the fuel in suspension in a PC boiler can be efficiently burned in a CFB boiler.

Start-up and load ramping Owing to the large mass of bed material and larger quantity of refractory in a CFB boiler than a PC boiler, CFB boilers are somewhat less suited for numerous start-ups and cycling service than are PC boilers. The large mass of bed material results in significantly higher thermal inertia in a CFB boiler than in a PC boiler. Start-up from cold conditions can be extended for several hours. This higher thermal inertia can also result in unstable bed performance during periods of rapid load changes. Especially in the case where sorbent feed for the FGD is being optimized, base load operation is preferred to enable consistent bed inventory and to ensure consistent desulfurization and sorbent utilization.

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Availability and reliability Over the past 25 years that CFB boilers have been utilized for steam generation for electric power generation, their availability and reliability have improved and at this time are considered to be equivalent to PC boilers. Several improvements in refractory-system designs, fuel- and sorbent-feed-system designs, and ash-extraction-equipment designs have been made that adequately address the initial problems encountered with these system components. As CFB boiler systems do not have pulverizers and do not have multiple burner systems with large numbers of moving or controlled components, and have significantly fewer sootblowers, many of the high-maintenance components of conventional PC boilers do not exist with CFB boilers.

Technology maturity Even though CFB boilers have been operating to provide steam for reheat turbine electric power generation for over 25 years, the steaming capacities have in most cases been limited to no more than 150 MW. Recently, this size has increased to the point where there are several reheat boilers in service supporting electrical power generation up to 300 MW (gross) output. These units are currently in service and under construction designed to burn the full range of solid fuels from low-volatile anthracite and petroleum coke to high-volatile bituminous coal and high-moisture lignite. CFB-boiler manufacturers are currently proposing to supply units with capacities in excess of 550 MW electrical output. PC boilers have been installed and operating with steaming capacities sufficient to support up to 1,300-MW electrical power generation. Owing to economies of scale for PC boilers and their auxiliaries, PC boilers installed in recent years have been predominantly larger than 250 MW and have been designed to operate with supercritical steam pressure conditions and high steam temperatures to reduce fuel costs and flue-gas emissions.

Capital costs The comparative capital costs between CFB and PC boilers in the 150–300-MW size range are expected to be similar. The CFB boilers have the additional particulate separation device to return most of the entrained bed material back to the combustion chamber. PC boilers have pulverizers, burners, and significantly more sootblowers that CFB boilers do not require. PC boilers also require external SO2 removal equipment that CFB boilers do not require, conditional on the sulfur content in the coal. When the sulfur content in the coal exceeds the maximum SO2 removal efficiency of the CFB boiler, an external FGD system would also be required.

APPLICABILITY OF TECHNOLOGY OPTIONS TO KUYASA From the available options discussed earlier, the selection of the boiler technology that would best fit the Kuyasa electric-power generating station can be made by analysing and utilizing the resources that are critical for the sustained operation of the power station and which are readily available at or in the general proximity of the proposed site. The main resources that influence the selection of boiler technology are fuel coal and its quality, water availability, and sorbent type and its availability. These resources are discussed in the following sections.

Fuel-coal characteristics Fuel coal from the Delmas Coal mine is selectively mined by Kuyasa and can thus be available in a wide range of characteristics and quality. Significant coal reserves are available from Seam No. 4 at a lower mining cost than from Seam No. 2. The upper layer of Seam No. 4 coal is characterized by having lower heating value and higher ash content than the lower layer of Seam No. 4 and Seam No. 2 coal. The higher-quality Seam No. 2 coal can still be mined and utilized for the proposed power station; however, it is more economical to utilize Seam No. 2 coal and the lower layer of Seam No. 4 coal as an alternative (backup) coal, and use the upper layer of Seam No. 4 low calorific value, low volatility and high-ash content as the design coal for the power station. As we discussed on the impact of coal quality on boiler technology and on its high ash content, the upper layer of Seam No. 4 coal is more suitable for a CFB boiler

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which can burn a lower heating value and volatile matter coal than the PC boiler. Furthermore, a CFB boiler can also burn the Seam No. 2 coal as an alternative fuel supply, or a blend of the two seams, if needed.

With the average qualities of the No. 4 Upper Seam coal, a total electric power generation of 600 MW using CFB boilers will require 375 t/h of design coal or approximately 84 million tonnes of design fuel coal over a 30-year life of the station at 85% plant capacity factor. The proven Seam No. 4 reserves are approximately 200 million tonnes. The proven reserves will accommodate future power station expansion; however, some blending from other reserves may be needed should the station expand to 2,400 MW. The fuel-flexibility advantage inherent in CFB boiler technology, as we discussed, will allow for supplemental fuel to be added to the base fuel as a blend coal or used as a complete alternative and allow for station capacity expansion in the future that will be capable of burning a wide range of fuel coal.

Water availability The water supply resources are known to be limited in Mpumalanga Province. Rand Water has development plans to bring additional water through a pipeline to serve future demands in Mpumalanga, and the proposed supply pipeline will be located near the mining operations and proposed plant site.

The water requirements for a 600-MW coal-fired power station vary significantly with the type of equipment used to produce power. A power station with conventional PC boiler and wet FGD equipment could use very high volumes of water a day (in excess of 10,000 m3/day). On the other hand, a CFB-based power station of the same size with air-cooled steam cycle and external dry FGD system (when needed) would use less than 4,000 m3 of water a day.

Note also that most of the water consumption estimated for the CFB boiler is for the external FGD system that would be required if the sulfur content in the coal exceeds the maximum SO2-removal efficiency of the CFB boiler. Should the sulfur content in the coal remain within the operational limits of the CFB boiler, the water consumption by the power station would decrease substantially.

The difference in water consumption between the two technologies is significant therefore, and it is doubtful and perhaps cost prohibitive for the Rand Water Development project to satisfy the water requirements of a plant using PC-boiler technology. Considering that there are some ground water resources in the vicinity of the power plant, Kuyasa Mines will try to tap these resources as soon as these are confirmed to be reliably available.

Sorbent availability Boiler technology selection directly impacts the method of SO2 removal from the flue gas. PC boilers require external FGD systems to neutralize SO2 in the flue gas after combustion of fuel coal has taken place in the PC-boiler furnace. The most common desulfurization systems used with PC boilers are the spray dryer absorber (SDA) also known as dry scrubber, and wet flue gas desulfurization (WFGD) also known as wet scrubber. Dry scrubbers typically use powdered lime as the neutralizing agent, whereas wet scrubbers typically use limestone slurry. Limestone slurry in WFGD scrubbers require a steady supply of make-up water to convert milled limestone to limestone slurry, and to make up for losses in the FGD process due to blow-down, evaporation, and carryover with process waste.

With CFB boilers, external FGD systems are typically not required as the SO2 removal process occurs in the bed of the CFB furnace during combustion of the fuel coal. Flue gas leaves the furnace already treated by desulfurization. However, this process advantage is conditional as it requires the sulfur content in the coal not to exceed the maximum SO2 removal efficiency of the CFB. Should the sulfur content exceed the maximum SO2 removal efficiency of the CFB, an external FGD system will be required to supplement the CFB in reducing SO2 emissions to allowable limits.

Crushed limestone or dolomite is fed into the CFB boiler with the fuel coal to form a bed of combustion material at the bottom of the furnace. The bed is fluidized with air and calcium oxide, which is formed from the calcination of limestone or dolomite, reacts with SO2 to form calcium sulfate, which is then removed from the flue gas with a conventional particulate-removal device.

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Sorbent consumption rate is significantly higher with CFB boilers than with external FGD systems used with PC boilers. However, when compared with wet scrubbers used with PC boilers, process water is not required for sorbent used with CFB boilers, thus eliminating the need for make-up water, limestone mills, and slurry process equipment. When compared with dry scrubbers used with PC boilers, the quality and cost of crushed limestone or dolomite used with CFB boilers is much lower than the processed powdered lime required for SDA used as dry scrubbers with PC boilers. When a dry scrubber is used to supplement a CFB, the amount of lime required would be significantly lower than that used by the dry scrubber of a PC boiler, as most of the SO2 would be removed in the bed of the CFB boiler.

Dolomite is somewhat less efficient than limestone in removing SO2 from flue gas owing to a lower content of calcium oxide and the presence of magnesium and manganese oxides, which are inert phases that are carried over with the post-combustion products. Therefore, using dolomite to neutralize SO2 in a CFB of the proposed power station will increase the sorbent consumption significantly over that of limestone. The increase in consumption will depend on the characteristics and calcium content of the dolomite used. Table 1 lists the three dolomite sources available in the proximity of the proposed power-station site, and indicates the expected relative consumption percentage of each source. A base limestone source is also listed as a typical sorbent and is used for comparison purposes. For the proposed 600 MW power station, the expected sorbent consumption using a typical limestone source with 95% CaCO3 content would be approximately 400,000 t/y. The three dolomite sources indicate an increase in consumption from 33% to over 300%. The increase in cost due to the additional consumption of dolomite over limestone would be partially offset by lower transportation costs and secured availability of dolomite in the proximity of the proposed site of the power station.

From the data provided in Table 1, and with the estimated consumption of a typical limestone sorbent of 400,000 t/y, the Kuyasa power station would be expected to consume the following amount of sorbent based on each source:

• Dolomite Microfine..............................................730,000 t/y • Dolomite Hiqua................................................... 530,000 t/y • Dolomite Lyttelton ............................................1,300,000 t/y Microfine dolomite (MFD) is not recommended as a sorbent in the CFB boiler as it does not

meet minimum particle-size specifications. The extremely fine particles of the MFD dolomite would leave the fuel bed in the CFB boiler with the fluidizing air, thereby reducing the contact time with the fuel coal and minimizing the reactivity of the sorbent with SO2. Reactivity is largely dependent on the properties of the sorbent and on the amount of time the sorbent is in contact with the fuel coal in the combustion stage. The particle size of the sorbent must be carefully evaluated in the laboratory to determine the size required for optimum reactivity based on coal characteristics, sorbent composition, and furnace configurations. It is typical for CFB-boiler suppliers to conduct this measurement prior to proceeding with boiler design and providing performance data.

Table 1. Comparison of available sorbent sources

Sorbent

CaCO3 content

[%]

Molecular wt of Ca [g/mol]

Molecular wt of

sorbent

Mole % Ca

CaCO3/ 100 kg sorbent

[kg]

Ca/100 kg sorbent

[kg]

Increase in consumption

[%] Limestone 95 40.08 100.09 0.4004 43.13 17.27 Base Dolomite MFD

52 40.08 100.09 0.4004 23.60 9.45 82

Dolomite Hiqua

71 40.08 100.09 0.4004 32.23 12.90 33

Dolomite Lyttelton

29.84 40.08 56.08 0.7147 7.59 5.42 300

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CONCLUSIONS AND RECOMMENDATIONS The Kuyasa power-generating station considered in this study can be developed by utilizing CFB-boiler technology based on the following conclusions and recommendations:

• Fuel coal is available on-site in a wide range of heating values, volatile matter, sulfur content, and ash composition. Kuyasa has indicated a strong desire to be able to utilize all available coal from the various seams, and the flexibility to be able to burn any one or blend of different coals. Only a CFB boiler has the flexibility to burn such fuels without sacrificing performance.

• Flue-gas pollution-emission limits as dictated by Eskom and the World Bank must be complied with to limit SO2 emissions and prevent the formation of acid rain. Various technologies are available for this purpose; however, only a CFB boiler can best limit SO2 emissions internally during combustion of the fuel coal, thereby eliminating the need for external SO2 removal equipment. This is true up to a certain value of sulfur content in the fuel coal. Should this value exceed the maximum SO2 removal efficiency of the CFB, an external FGD would be required to supplement the CFB in SO2 removal. A CFB boiler can use a wide range of sorbent characteristics within its combustion bed to neutralize SO2. A PC boiler would require either high-quality and costly pulverized lime to be used with a dry scrubber (SDA), or limestone slurry to be used with a wet scrubber (WFGD), which requires a significant amount of process water, a resource that is not abundantly available at the proposed site.

• Dolomite sorbent is available in large supplies from quarries near the proposed site for the Kuyasa power station. Transportation and delivery costs of dolomite, which could be used as a sorbent for a CFB boiler, would be more economical than a higher-quality sorbent, such as pulverized lime or crushed limestone, which would be required for a PC boiler with external flue-gas desulfurization equipment. A CFB boiler has the flexibility of using either crushed dolomite or limestone for sorbent purposes. This flexibility allows the power station to use either sorbent selectively, based on supply and market conditions. Should an external FGD system be required to supplement the CFB in SO2 removal during periods when coals higher in sulfur are burned, the amount of lime needed for the external FGD would be significantly lower than that required for a PC boiler external FGD, as most of the SO2 is absorbed initially in the CFB boiler.

• The CFB boiler technology has made significant advances in the past 25 years such that the reliability of CFB boilers rivals that of PC boilers. The introduction by Kuyasa of CFB-boiler technology to South Africa could open the door for Eskom and other power developers to burn lower-grade and lower-cost fuel coal and utilize more of the country’s available resources.

• Given the available low-grade coal and expected early production in the foreseeable future, it is estimated that about 6,000 MW of power can be generated with low-grade coal utilizing CFB-boiler technology.

• The power station configuration of a 4 × 150 MW base or a 2 × 300 MW alternative arrangement presents a significant advantage in the CFB boiler market as the 150-MW boiler size has become one of the more popular sizes worldwide. The major CFB boiler suppliers have installed a significant number of boilers of this size and have established reliable operating experience with these boilers. The 300-MW CFB boiler is quickly gaining popularity among power utilities and its reliability is approaching that of the 150-MW boiler. The 300-MW CFB boiler has the advantage of an economy of scale when compared with the 150-MW boiler, whereas 150-MW units have the advantage of redundancy and more power output when one unit is taken out for service.

• Coal fluidization technology holds a promising future in South Africa and should be given due consideration by IPPs.

It is the recommendation of this study to configure the first phase of the Kuyasa power-generating station as a 600-MW station comprising 4 × 150-MW units, with an alternative arrangement of 2 × 300-MW CFB units.

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