A review of some operation and maintenance issues of CFBC boilers

Applied Thermal Engineering 102 (2016) 672–694

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Applied Thermal Engineering journal homepage: www.elsevier.com/locate/apthermeng

A review of some operation and maintenance issues of CFBC boilers Anand Arjunwadkar a,⇑, Prabir Basu a, Bishnu Acharya b a b

Greenfield Research Incorporated, PO Box 25018, Halifax B3M 1N8, Canada School of Sustainable Design Engineering, University of Prince Edward Island, 550 University Avenue, Charlottetown, PEI C1A 4P3, Canada

h i g h l i g h t s
Detailed review of operational issues in a circulating fluidized bed boiler.
Practical solutions for some of the operation and maintenance issues.
Preventive maintenance procedures to predict, avoid or detect failures.

a r t i c l e

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Article history: Received 16 February 2016 Revised 31 March 2016 Accepted 2 April 2016 Available online 2 April 2016 Keywords: Start-up Safety Emissions Refractory Ash coolers Corrosion CFB boiler

a b s t r a c t Circulating Fluidized Bed (CFB) technology has emerged as the most favoured steam generation technology in recent times. The use of CFB boilers is growing exponentially, due to its attractive features such as fuel flexibility, stable operation and low acid gas emissions, to name a few. The design of CFB boilers has developed over the years to meet the demanding availability expectations of the utilities. Proactive operation and maintenance (O&M) helps improve availability and reduce operating costs, which form a crucial component of the final steam cost of the boiler plant. This paper studies some important O&M issues of CFB boilers particularly looking into issues related to components specific to CFB boilers and the methods to avoid them. Operational difficulties like agglomeration, gas refluxing, back-sifting and performance related issues like emission control and bed temperature control are also examined. Refractory failure, which accounts for a considerable portion of the maintenance cost often forces shutdowns. This review is based on compilation of O&M issues of CFB boiler as found mainly in the open literature, but some unpublished information are also included. Ó 2016 Elsevier Ltd. All rights reserved.

Contents 1. 2. 3.

4.

5.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Start-up issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Safety issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1. Explosion potential in a CFB boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2. Hot solid discharge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3. Lime burns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4. Hydrogen sulfide leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5. Carbon monoxide accumulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Issues related to bed material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1. Selection of start-up bed material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2. Slagging, agglomeration and clinkering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3. Air distribution across bed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bed temperature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1. Effect of fuel feed rate on bed temperature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2. Effect of bed particle size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3. Effect of primary air supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

⇑ Corresponding author. E-mail address: [email protected] (A. Arjunwadkar). http://dx.doi.org/10.1016/j.applthermaleng.2016.04.008 1359-4311/Ó 2016 Elsevier Ltd. All rights reserved.

674 674 675 675 676 676 676 676 676 676 677 677 677 678 678 678

A. Arjunwadkar et al. / Applied Thermal Engineering 102 (2016) 672–694

6.

7.

8.

9.

10.

11. 12.

13.

14.

5.4. Effect of oxygen concentration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5. Effect of bed height (dense zone height) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6. Effect of load on the unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7. Effect of pressure drop across lower bed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1. Sulfur dioxide emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.1. Combustion temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.2. Excess air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.3. Bed density & circulation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.4. Properties of sorbent & bed material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5. Cyclone/separator efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2. NOx emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3. CO emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4. N2O emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loopseal malfunction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1. Surging/blocking of loopseal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2. Agglomeration in loopseal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3. Plugging of loopseal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.4. Gas back-flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5. Special issues in petcoke fired boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Refractory related problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1. Anchors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2. Refractory challenges in a CFB boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1. Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2. Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3. Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3. Refractory failure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.1. Thermally induced failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.2. Failure of anchoring system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3.3. Failures related to workmanship . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4. Initial curing/dry-out. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tube failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1. Mechanical wastage/wear. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.1. Interface between refractory lining and waterwall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.2. Corners formed by water-wall panels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.3. Suspended heat transfer surfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.4. Fluidized bed heat exchangers (FBHE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2. Gas side corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bed nozzle issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1. Design factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.1. Operational characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.2. Fuel characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.3. Location of nozzle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.4. Deflection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2. Operational factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.1. Erosion of nozzles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.2. Enlargement of orifices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.3. Back-sifting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expansion joint failure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ash coolers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.1. Fluidized Bed Ash Coolers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.2. Screw ash cooler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3. Air cooled ash cooler. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.4. Rotary ash cooler. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maintenance of CFB boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1. Reactive maintenance (breakdown maintenance). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2. Proactive maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.1. Fluidization uniformity test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.2. Particle size distribution monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.3. Pressure drop test of distributor nozzle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.4. Fluidized bed pressure drop test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.5. Monitoring pressure drop across furnace and cyclone. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.6. Cyclone temperature rise (post combustion) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.7. Online sampling of solids from loopseal for size distribution analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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1. Introduction Sustained supply of fuel from a single source and at a predicted price has been a major concern for power generation industries. The price of traditional fossil fuels has been fluctuating. At times it is increasing and another time it shows a downward trend. In recent past price of coal and oil has been decreasing but nonconventional or ‘opportunity’ fuel like petcoke is providing even price on per unit heat delivered. The carbon neutral biomass fuel or solid wastes like Municipal Solid Waste (MSW) also provides good opportunity as boiler fuel at very attractive price. Moreover, the consistent availability of conventional design fuel has also been an issue. Also, at times it is commercially more attractive to sell the premium design fuel in the market than using it in the power plant. In such scenarios many power companies are taking fuel mix as an option to minimize the impact of changing price of fossil fuels while at the same time addressing the emission issues. Pulverized coal (PC) firing is the most commonly used combustion technology for power generation, but it has limited fuel flexibility, making it difficult for industries to switch to less costly nonconventional opportunity fuels as they become available. Additionally high performance boiler technology like ultra-supercritical boiler favors CFB firing over PC firing for many practical reasons beside its fuel flexibility benefit [1]. This is motivating many power companies to move towards circulating fluidized bed (CFB) firing. Because of its fuel flexibility feature and lower NOx emission and easy SO2 capture, CFB firing is becoming increasingly popular among the power companies around the globe and therefore, its installation is growing exponentially in last decades (Fig. 1). Since early 1980s large amount of research has been conducted in both fundamental and practical aspects of circulating fluidized bed (CFB) boilers technology. This developmental and research work has greatly improved the CFB boiler technology, which was in early days confined to less than 30 MWe capacities and with prices nearly twice that of competing PC fired boilers. Today, CFB boilers are operating in capacities up to 600 MWe and at prices comparable to those of PC boilers. It has thus become an attractive option for utility and process industries especially those who have limited access to consistent supply of good grade fuel. While the use of CFB boiler has grown greatly, its operational availability has not been very attractive in some parts of the world. Ideally, CFB boiler is a relatively stable and trouble free technology, but in some parts of the world CFB boilers are facing more than expected share of outage reducing the boiler availability to as low as 60%. Although much has been published and discussed on theories and on operation of ideal CFB boilers, very little is discussed or published in open literature about the real life issues regarding its operation and maintenance. This paper presents different operation and maintenance issues and problems that results in failure

Fig. 1. Increase in capacity of single unit CFB boiler [2].

or performance reduction of CFB boilers. The issues discussed include the following:













Start up Safety Bed material related Bed temperature control Emission control Loopseal malfunction Refractory failure Tubes failure Grid nozzles erosion Expansion joints failure Ash coolers underperformance General maintenance issues

The challenges and issues related to the above topics are discussed in individual sections.

2. Start-up issues Start-up covers the time period in which operation of a boiler is initiated (electricity or steam generation) [3]. It begins with the first fuel firing in the boiler after a shut down. The start-up period ends when the boiler generates electricity or useful thermal energy, whichever is earlier [3]. Like pulverized coal fired (PC) boilers circulating fluidized bed (CFB) boilers have three different types of start-up procedures, namely [4]: (a) Cold start-up: The boiler starts from ambient cold conditions with negligible or no residual heat since the last shutdown. (b) Warm start-up: The start-up following an off-line period between 6 and 12 h. (c) Hot start-up: The start-up following an off-line period of less than 6 h. The start-up involves burning of an auxiliary fuel source such as, oil or natural gas. A CFB boiler typically employs one of three start-up methods: over bed, under bed and combined ignition methods [5]. In over-bed firing, start-up burners are located in the lower furnace at an angle directed towards the bed. These burners also serve the purpose of supplementary firing to maintain bed temperatures at low load conditions if needed [6]. They are not as efficient (heat utilization is less than 45%) as the under-bed start-up system [5] that consist of in-duct burners located in the primary air duct to heat the primary air, which in turn heats the bed material. This system is more efficient (heat utilization 90%) and the bed is heated uniformly (see Table 1). The start-up time required with under bed systems is therefore lower than that with the over bed start-up systems [5]. Expansion joints are needed between the primary air duct and wind box to allow the rapid differential expansion with change in temperature of primary air in under bed systems. The construction and maintenance of such expansion joints is difficult due to their location [5]. In combined start-up systems, both over-bed and under-bed burners are used. These systems combine the advantages of both the start-up systems. Basu & Ghosh [7] developed an alternative novel economic start-up system where a certain amount of design or other solid fuel is premixed with the starting bed material. It helps raise the temperature of the bed solids for reduced use of gas or oil. Reduction in start-up time can have significant reduction in auxiliary fuel consumption and the cost associated with it. Some of the methods to reduce the auxiliary fuel consumption during start-up are:

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Table 1 Comparison of start-up systems. Over-bed start-up

Under-bed start-up

Combined start-up

Burners located above lower furnace Heat utilization 645% Longer start-up time Burners can be used at low loads for supplementary firing

Burners located in primary air ducts Heat utilization 690% Lower start-up time Difficult to design, construct & maintain

Burners located in primary air ducts as well as above the furnace Combine advantages of both systems Increased cost Higher capital cost


Optimization of bed material height and bed material size distribution [5]. Adequate bed height ensures maximum heat utilization of the over bed burner’s flame and the optimum size distribution ensures the material is not entrained unnecessarily.
Adding a charge of more reactive fuel at the right time during start-up helps raise the bed temperature above the threshold limit for self-sustained combustion of the design fuel [7]. Premixing an optimum amount of reactive fuel along with the bed material during start-up increases the bed temperature rapidly [7].
Use of the duct burner in case of combined ignition systems [5].
Less expensive used (waste) oil can be burnt in a CFB boiler during start-up for cost saving as well as disposal of waste fuel. It can be fired from the regular burner or by bed oil lances as long as the viscosity is same as that of the fuel oil and no impurities are present in it. Used oil may sometimes cause fouling, and in such cases it must be used in quantities no more than 30% of the total heat input of the burners.
The oil guns maybe placed in the vicinity of the secondary air nozzles to improve the combustion of oil and rapid mixing with air [8].
To maintain flame stability the height of the burner above the static bed and the burner angle needs to be optimum [8,9]. In some incident an ignition in a boiler could not be started even after 20 h of start up burner due to incorrect orientation to the bed.
Slagging may be observed on the lower parts of diverging conical ports opening into the furnace that are typically used for for natural gas burners [6]. Due to the slagging and plugging, the burner flame could be deflected and the heating up of the bed may proceed slowly. De-slagging these ports before start up is a time consuming task. This phenomenon is prevalent for fuels with high alkali content like municipal wastes. The reason for this slagging is low capacity of burners and formation of recirculation zone at the burner port [6]. Increasing the capacity of the burners or modifying the burner opening to cylindrical instead of conical can avoid this slagging problem. 3. Safety issues CFB boilers are intrinsically much safer than PC boiler owing to the absence of flame and explosive gas mixture in the main furnace. It does not therefore require sophisticated burner management systems with safety interlocks. It has, however, some minor safety issues which are described below. 3.1. Explosion potential in a CFB boiler From fire safety consideration, explosions can be defined as a sudden conversion of potential energy (chemical or mechanical) into kinetic energy with the production and release of gas(es) under pressure [10]. Explosions in a boiler can be classified as fire-side or air-side explosion depending on the area in which they occur. Fire-side explosions occur in the furnace or along the flue gas path due to accumulation of combustible gas. Air-side

explosions are those, which occur in the primary air duct or windbox. Some common situations, which could cause fireside explosions in a boiler, are listed below [11]:
Interruption of fuel, air supply or ignition energy to burner can result in momentary loss of flame. Re-ignition in such a case could lead to an explosion due to accumulation of fuel in the furnace.
The ignition of auxiliary fuel (oil/gas) that leaked into the furnace could cause an explosion.
Repeated unsuccessful attempts to light off auxiliary fuel during start-up without appropriate purging could result in the accumulation of an explosive mixture in the furnace.
Fuel accumulation in a fluidized bed during a period when temperature drops below that of the fuel ignition temperature can cause an explosion in case of sudden ignition by an external source.
Purging with an airflow high enough to stir combustibles smoldering in hoppers could also cause explosion.
In case of large cross-section furnaces, insufficient primary air supply in some region of the furnace can cause incomplete combustion and prompt accumulation of combustible material in those pockets creating explosion potential.
There may exist some dead pockets in the furnace enclosure or other parts, which are susceptible to accumulation of combustibles. These combustibles can cause an explosion in presence of an ignition source. Following measures can reduce the rise of fireside explosion:
Human error proved to be the most common cause for fireside explosions [11]. So, proper training of operating staff could reduce such risk of explosions.
Operating procedures should be designed so as to reduce manual operations and introduce interlocks to stop the operation sequence in case of improper conditions. Written operation sequence and checklists, with all manual and automatic function, should be provided to guide the operator [11].
Fuel feed should be started only when the bed temperature is above the highest ignition temperature for the range of fuels being fired.
A fuel rich mixture should be avoided at all time [12].
Elimination of fuel metering system to reduce cost is practices in some parts of the world, but it is an unsafe option. Regular calibration of fuel feed metering devices could reduce the risk of over feeding fuel into the furnace.
Necessary purge procedures should be followed before the start-up procedures are initiated [11].
Explosion vents or explosion doors should be provided at suitable locations in the flue gas path or windbox to reduce the maximum explosion pressure and protect the boiler component [13].
Installing flame sensors or flame monitors for burners would trip the auxiliary fuel supply to the burners [14] in a flameout condition during start-up and prevent the accumulation of auxiliary fuel in the bed/furnace.

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‘Back sifting’ is a phenomenon observed in fluidized bed boilers where bed hot solids drop into the air box through the furnace grate. It is known to be the foremost reason for explosion. The fuel in the back-shifted bed material continues to smolder in the air box after shut down of boiler. Carbon monoxide accumulates in the windbox due to insufficient air for combustion. This accumulation may lead to an explosion when in-duct burner flame ignites the gas [12]. The air purging supplied during hot start up may in turn be the reason for air side explosion under the bed. During hot start up, back-sifting of hot solids into the windbox could occur through grid nozzles. The purge air supplied provides the oxygen and help suspend the combustible particles lying on the floor of the windbox. The hot solids act as the source of ignition, resulting in explosion. An effective measure taken to avoid such explosion during hot startup is purging with steam. Also, proper grid nozzle design, frequent cleaning the windbox and avoiding smolder formation help prevent air side explosion. Finely divided solids, when dispersed in air, can cause dust explosion in a confined space [10] and lead to fire in an open area. Any oxidizable or combustible finely powdered material can form a flammable dust cloud in air [15]. Dust explosions can occur in a variety of materials such as coal, sawdust, agricultural biomass, metals and plastics. Dust accumulation is found in many parts of the boiler house, particularly surrounding fuel conveying systems, fuel silo discharge, hopper discharge and fuel feeding equipment. In some cases, dust explosions can occur in the dust collection systems. Dust often settles down forming a layer of powder on equipment floor. Explosions or fires caused by the dispersion of such settled dusts are called secondary dust explosion [16]. Some methods to prevent dust explosions/fires are:
Solid handling equipment should be manufactured and sealed in order to prevent leakage of material.
Regular cleaning of areas prone to dust settlement with dedicated vacuum cleaners which are not an ignition source themselves will reduce the risk of secondary dust explosion. Water sprays can also be used for cleaning or to limit dispersion in suitable applications such as coal conveyers. 3.2. Hot solid discharge Solids from a fluidized bed flow like a liquid when drained through an opening [17]. Hot solids in a CFB furnace therefore can spill out as a consequence of failure of the bottom ash removal device or furnace wall rupture [12]. Such hot spills can injure personnel and damage equipment. Fuel lines and wiring should be routed away from ash drain and ash removal devices [18]. The bed material in the furnace and connected components remains hot even long after shut down. Personnel should enter the furnace or other component only after verifying the temperature of bed material [18]. Additionally, a contact of hot solids with water causes rapid generation of steam (steam explosion) [18], which can cause splattering of hot solids and lead to injuries. In one particular incident, a worker entered a FBHE long after shut down for inspection. Having noted a blockage in the inclined solid pipe from the furnace he poked and an avalanche of hot solid fell burying the worker in no time. 3.3. Lime burns Since complete utilization of sorbent particles is not possible, limestone in excess of what is theoretically required is fed into a CFB boiler for sulfur capture. Significant amount of limestone is

therefore not converted to calcium sulfate and appears in the bottom and fly ash as calcium oxide (quicklime) [12]. Calcium oxide reacts with water or water vapor to generate heat and could even react with moisture on skin or eyes of personnel to cause chemical burns [18]. Operators should be trained and provided with protective gear such as, breathing masks, eye protector and proper clothing to handle ash. Design of ash conditioning systems utilizing water should consider the effect of this exothermic reaction [18]. 3.4. Hydrogen sulfide leakage The lower furnace of a CFB boiler, which operates under substoichiometric conditions, can produce hydrogen sulfide (H2S), an intermediate product before oxidation of sulfur, under certain conditions. H2S is highly corrosive, poisonous and flammable. It is heavier than air and in case of a leakage it could accumulate in lower levels of the plant [18]. Lower furnace should be completely sealed and the boiler house should be equipped with devices for H2S concentration detection and measurement. O&M personnel should be trained to anticipate and respond to a H2S threat. 3.5. Carbon monoxide accumulation Carbon monoxide may accumulate in the furnace, cyclone or flue gas duct after shutdown, due to smoldering of combustibles. Proper purge procedures should be followed before entering the furnace. Carbon monoxide sensors should be used to measure the concentration as it is an odorless gas as it can be fatal if inhaled in excessive quantity. There is at least one incident where an inspector entered a cyclone and died of exposure to CO. 4. Issues related to bed material Bed material is an inert, non-combustible solid medium made up of granular limestone, re-circulated ash and aggregate material such as silica sand or custom refractory material. It has three main functions in a CFB boiler, namely [19]: heat storage, temperature stabilization and act as sulfur sorbent. An ideal bed material should be relatively inexpensive, widely available, hard, resistant to attrition and non-contributing to formation of eutectics with ash [5]. The size distribution of bed material affects the range of superficial gas velocity, heat transfer and hydrodynamics [17]. Some of the common concerns regarding bed material are discussed in the following sections. 4.1. Selection of start-up bed material Bed materials commonly used are retrieved bed solids from the previous boiler run, limestone and silica sand. Selection of start-up bed material plays an important role in quick and trouble free start-up of the boiler. For start up the bed material should be within the specified size spectrum and should not be friable. The most commonly used bed start-up bed material is the discharged bed material or bottom ash from the bottom ash collection system retrieved from the previous shut down. It is inexpensive and can be bought from another operating CFB boiler unit as well. Such recycled bed material is already of the required size, hence no screening is required. Other benefit of such bed material is that it is not friable, since it has already undergone the rigorous attrition. Limestone has been used as a start-up bed material in many boilers where sulfur is captured in-situ. It can also be used if there is no system to re-inject bottom ash back into the furnace. But limestone as start-up bed material has some shortcomings:

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Limestone available in the silos is ground to an optimum size for sulfur capture. This limestone is easily entrained on fluidization and requires to be replenished. Thus for start up a coarser limestone (200–800 lm) is recommended instead of the fine size fed into the bed for sulfur capture.
Limestone is friable and easily undergoes attrition, which further reduces the size of the particles.
Some entrained particles are recirculated back to the combustor through the loop seal. Such fine particles if below 75 lm are difficult to fluidize and lead to difficulty in fluidization in the loopseal.
The CaO from limestone acts as a catalyst in the formation of NOx. Thus the NOx emissions could be high during start up. 4.2. Slagging, agglomeration and clinkering Slagging can be defined as the formation of deposits on solid surfaces due to the molten or softened ash. Clinkering on the other hand occurs within the body of bed material due to melting or fusion of bed solids. Agglomeration is temporary or permanent joining of small particles to form larger lumps. All or any of these could occur in the fluidized bed if the bed temperatures exceed the ash fusion temperature specified by the standard ASTM ash fusion tests. Although CFB boilers operate at low temperatures (850–900 °C) clinkering can be observed in the furnace during start up [5] when local hot spots are formed. During start-up of the boilers the fuel flow is started after the bed temperature reaches a specified temperature, which depends on the fuel properties. When fresh fuel is fed, it immediately mixes with neighboring bed material and absorbs heat from it. This reduces the bed temperature temporarily, which can prompt the operator to increase the fuel supply. Once the combustion starts, this excess fuel in the bed can cause rapid temperature rise above the ash softening temperature and cause agglomeration. Unless prompt action is taken a lack of heat dissipation could further increase the temperature of ash above its fusion temperature and thereby form clinker. Slagging is also likely to occur due to insufficient airflow, uneven air distribution through the grid, insufficient heating surfaces in lower furnace or poor atomization of start-up oil gun [5]. Bed agglomeration could occur when individual bed particles adhere to each other to form larger particles [20], leading to defluidization. Bed agglomeration problems in fluidized-bed boilers are related to a high alkali metal content in the fuel. When the alkali metals react with sulfur, chlorine, silica and phosphorus, they form compounds with low melting points called eutectics [20]. These eutectics form a coating on the bed particles, which binds them together forming large agglomerates. The melting behavior of eutectics is very sensitive to the relative amounts of potassium and calcium in the fuel and bed [21]. Fast growing plants (annual crops) such as wheat grass have significant potassium and chlorine content [22]. Bed agglomeration is more prevalent in biomass co-fired boilers, since biomass ash has a lower ash melting temperature than coal ash [20]. Agglomeration is particularly damaging when it occurs in loopseal as it leads to stoppage of the boiler. Agglomeration is more likely to occur in the loop seal and external heat exchanger due to the fluidization velocity being lower than the combustor. Agglomeration can cause de-fluidization in the loop seal and external heat exchanger resulting in blockage of the re-circulation system. The chance of agglomeration increases in the presence of sodium and potassium, which act as fluxing agents. Alkali metals tend to promote agglomerate formation even if they are present in quantities not sufficient to form agglomerates [23]. Agglomeration due to sulfation of limestone derived materials can also occur in the absence of alkalis or vanadium. It is observed with fuels

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having lower ash content and higher sulfur content, in which case higher quantities of limestone is required [23]. Agglomeration in loopseals is a major issue in CFB boilers firing petcoke and it often forces the operator to fire a minimum amount of other types of fuel like coal to reduce the probability of agglomeration. In boilers firing pet-coke there is the formation of (V2O5) or (V2O4), which also causes agglomeration. Some practical options for reducing agglomeration are:
In case of biomass co-fired boilers, one can limit the percentage of biomass as per design of the boiler to reduce the risk of agglomeration [22].
Periodic fuel analysis and maintaining alkali and chlorine content of fuel within the design values of fuel could reduce the risk of agglomeration. The operating temperature of the loopseal and external fluidized bed heat exchanger should be kept below the ash fusion temperature of the fuel [20].
Unusual pressure drop fluctuations and steep temperature gradients detected in the furnace give warning of potential agglomeration 20–30 min earlier [24]. Corrective measures should be taken right away.
Bed additives such as iron oxide (Fe2O3) helps reduce agglomeration as potassium has a higher affinity to form compounds with the iron (Fe) component [25]. Additives such as kaolin and other clays also help reduce agglomeration [26]. Ferric oxide appears to be the only low cost option to reduce agglomeration [27].
Alternative bed materials such as limestone, mullite, magnesite, calcite, clay, bone ash, blast furnace slag can help prevent bed agglomeration [28]. Bed agglomeration can be reduced by presence of limestone, use of bed materials with low silica content (as silica is much likely to react with alkali in case of biomass), reducing sodium content in coal and potassium content in limestone [26].
Studies conducted by Lin et al. [29] on combustion of straw suggest that agglomeration at higher temperature forms smaller agglomerates. It is relatively easy to re-fluidize the smaller agglomerates formed in bed material once the bed temperature drops [29].

4.3. Air distribution across bed Primary air distribution in the bed could influence the combustion efficiency, limestone utilization, carbon monoxide and NOx production [30]. Distribution of primary air through the lower furnace is dependent on the design of the windbox and nozzle, but operating parameters also affect the uniform air distribution through the bed. The continuous monitoring of oxygen concentration in the bed is an effective indication of the primary air distribution. Plugged nozzles and uneven distribution of fuel feed could influence the primary air distribution. Uneven air distribution is observed near fuel feed ports due to the disturbance in horizontal mixing caused by influx of fresh fuel. Monitoring of oxygen levels at various locations in the bed could detect non uniform air distribution. Carrying out a fluidization uniformity test before every start up could help ensure even air distribution.

5. Bed temperature Steady and uniform bed temperature is an important requirement for the stabilization and safe operation of a CFB boiler. Bed temperature depends on unit load, coal quality, coal size spectrum, fuel feed rate, air supply rate (primary and secondary), ash removal rate [31]. The factors which can be controlled by the operator to

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Table 2 Effect of operating parameters on bed temperature. Parameter

Unchanged parameter

Change in parameter

Effect on bed temperature

Reference

Fuel feed rate Bed particle size Primary air supply

Primary air supply, bed particle size Primary air supply, pressure drop across bed Bed particle size, pressure drop across bed

Increase Decrease Increase

[31] [31] [31]

Depth of solids in dense zone

Primary air supply, bed particle size, pressure drop across bed All other parameters All other parameters

Decrease

Increase after a certain time lag Decrease Increases if the fuel feed rate is increased proportionately Decrease

Increase Decrease

Increases 0–30 s later Increase

[31] [32]

Load Pressure across bed

influence bed temperature are fuel feed rate, primary and secondary air supply rate and ash removal rate. The relationship between above mentioned parameters and bed temperatures is explained in Table 2. These are based on experiments conducted on a 450-ton/h circulating fluidized bed boiler in China by [31]. 5.1. Effect of fuel feed rate on bed temperature The bed temperature changes when the fuel feed rate is changed, but it occurs after a time lag. For example, when the feed rate is increased in a steadily operating bed, the bed temperature starts decreasing due to the cooling by additional mass of fuel feed. Thereafter, when the fuel mass starts burning, the bed temperature starts increasing. So, a sudden increase in fuel supply may lead to a decrease in bed temperature even below that for fuel ignition. Similarly, a decrease in fuel supply may not reduce the bed temperature immediately. During normal operation an increase in the fuel feed rate leads to a slight temperature drop of bed temperature but the lag is within 1–4 min after which the bed temperature begins to rise sharply. During hot start up, the temperature lag is prominent as the bed temperature is low and the coal particles absorb heat from the bed to reach the ‘ignition point’, in turn reducing bed temperature [31]. With increasing fuel supply the height of the dense zone could increase and with unchanged primary air flow rate the coal cannot mix well. This happens when the bed temperature is low enough to make the superficial gas velocity below that needed for vigorous bubbling. The fuel in this case may remain in the upper layer of dense bed with a risk of local clinkering. As the coal is ignited, the bed temperature rises sharply. The fuel feed should be reduced till the bed temperature stabilizes within the operational range and then the fuel can be fed at a constant rate as per stoichiometric requirements [31].

[31]

increases combustion efficiency and bed temperature when the fuel feed rate is also proportionally increased [31]. Increased primary air decreases the bed temperature at a constant fuel feed rate as the heat is carried by the flue gas away from the dense phase. During start-up, the primary air should be increased along with the fuel feed rate to increase the bed temperature, but during normal boiler operation (bed temperature: 780–900 °C and constant fuel feed rate) the primary air can be decreased to increase the bed temperature. Bed temperature can be controlled through an adjustment of primary air within a limited temperature range of 150 °C after which the adjustment of fuel feed rate is necessary. 5.4. Effect of oxygen concentration Oxygen concentration can guide the operator on how to control the fuel feed rate and primary air as it reflects the combustion condition in the furnace [31]. If the primary air supply is fixed and the oxygen concentration in the flue gas decreases, it indicates excess fuel is being fed. Thus, the operator should decrease the fuel feed rate to maintain the bed temperature. The opposite is also true. If the primary air is less than that required for a specified fuel feed rate, the bed temperature decreases for some time. This decrease in bed temperature may offer a wrong impression to the boiler operator, and he may increase the fuel feed rate to increase the bed temperature. This would further reduce the bed temperature. In this situation the oxygen concentration in flue gas will decrease and that will prompt the operator to either increase primary air supply or decrease fuel feed rate. 5.5. Effect of bed height (dense zone height)

The mean size or size spectrum of bed particles also has an effect on the bed temperature. If the size of bed particles is less than its design value, they will be transported to the dilute zone and the temperature of the lower bed will reduce due to decreasing combustible concentration in the dense zone [31] and higher particle suspension density in the upper furnace. This will in turn lead to better heat transfer and reduction of combustion temperatures and carbon loss through drained bottom ash. If the size distribution is found to be smaller than the design value, the bed temperature can be maintained by reducing the primary air supply rate and increasing the secondary air supply rate [31].

The static depth of solids in the lower bed gives a measure of the total solid inventory in the furnace as the total solid in the furnace never exceeds that is needed to fill the lower bed. During operation solid inventory in the lower bed referred to as ‘dense bed height’ as sensed by pressure drop across the lower bed has important bearing on the CFB operation. It is controlled to some extent by bed ash drain rate. If the ash removal rate is decreased for a constant supply of primary air and fuel feed rate, the height of the dense zone in the lower part of the furnace increases. This decreases the bed temperature, furnace exit temperature, main steam pressure, oxygen concentration and increases furnace pressure differential [31]. When dense zone height is changed, operators must adjust primary air accordingly to maintain bed temperature. In general, dense zone height increases, primary air must be increased, the opposite is also true.

5.3. Effect of primary air supply

5.6. Effect of load on the unit

Primary air has two principle objectives, namely combustion and fluidization. In case of combustion, increasing primary air

Bed temperature, which is one of the important parameters of a CFB boiler, has effect on the load of the unit [31]. The change in

5.2. Effect of bed particle size

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A. Arjunwadkar et al. / Applied Thermal Engineering 102 (2016) 672–694 Table 3 Effect of change in operating parameters on SOx emissions. Parameter Combustion temperature Excess air Bed density & circulation rate Reactivity of sorbent Size distribution of sorbent Separator efficiency Load

Change in parameter Increase Increase Increase Increase Increase

Effect on SOx emissions

Reference

Optimum temperature range is 800–850 °C Decrease Decrease Decrease Optimum if size distribution within range specified by boiler manufacturer Decrease Increase

[34,35] [17,36,37] [17,37] [34] [17,36,38,42] [34] [37]

load precedes the change in bed temperature. This is because the change in temperature of the upper dilute zone is observed before the change in temperature of the lower dense zone occurs. Since most of the heat transfer takes place in the dilute zone, the change in load is observed slightly before (0–30 s) change in lower bed temperature [31].

5.7. Effect of pressure drop across lower bed For a given feed rate, primary and secondary air flow rate a drop in bed pressure may indicate a loss of bed materials. This results in reduced recirculation rate of circulating material, thus the solid suspension density and consequently heat transfer are reduced with consequent rise in bed temperature. To maintain boiler output even higher bed temperatures are required. Higher bed pressure drop or higher bed inventory on the other hand, gives to stable bed temperatures at the expense of higher auxiliary power consumption [32].

6. Emissions 6.1. Sulfur dioxide emissions Circulating fluidized bed boilers are a preferred choice for fuels with high sulfur content (High Sulfur coals are classified as those which contain more than 1.68 pounds of sulfur per million BTU or 4.29  107 kg of sulfur per gigajoule, EIA [33]). The efficiency of sulfur capture depends on many operating parameters as well as on the sulfur content in the fuel and the properties of the sorbent used. The effect of some parameters are discussed in the following sections (see Table 3).

6.1.1. Combustion temperature The reactivity of sorbent increases with a rise in combustor temperature and is optimum in the temperature range of 800–850 °C [34,35]. The conversion rate to CaSO4 decreases with further increase in temperature as the calcium oxide pores are plugged at a faster rate by higher molar volume CaSO4.

6.1.2. Excess air Increased excess air shows reduction in the limestone utilization [36]. Higher excess air does not allow formation of oxygen deficient regions, which reduce CaSO4 [17]. The oxygen level in the combustor is a good indicator of excess air. The experiments conducted by Mii et al. [37], on a 70 ton per hour commercial boiler in Japan confirm the advantage of higher excess air on SO2 emissions. The reduction in SO2 concentration in flue gas may also be an effect of dilution. When excess air is reduced at constant combustor temperature, SO2 emissions increase, but on the contrary NOx emissions reduce due to promotion of reducing reaction [37].

6.1.3. Bed density & circulation rate Sulfur dioxide (SO2) emissions reduce because of increasing bed density caused by increased circulation rates [37,38]. The positive effect of increased circulation rate on sulfur capture is attributed to the increase in sorbent residence time within the furnace [39].

6.1.4. Properties of sorbent & bed material Sorbent properties such as Ca content, reactivity, accessibility of outer/inner particle surface (pore size distribution) and particle size have important effects on the SO2 emissions in a CFB boiler [34]. A sorbent with greater Ca content and better reactivity1 will have better sorbent utilization. Fine pores in sorbent particles provide higher surface area for sulfation per unit weight of sorbent but entrances of these pores are easily blocked [40]. Limestone with reactivity R2 = 58% has better sulfur capture efficiency at a lower Ca/S ratio. There is an optimum size of limestone for sulfur capture. Sorbent particles larger as well as smaller than this specific size result in poor sulfur capture [38]. An optimum size of average bed material affects the hydrodynamics, residence time, heat transfer and separator efficiency [42]. The acceptable range of limestone and fuel particle size distribution is specified by the boiler manufacturer. For example, good bed quality may be defined by bed materials in the range of 80–300 lm [36]. Good bed quality is beneficial because here solids are entrained from the lower furnace into the upper, and are captured by the cyclones and returned to the process.

6.1.5. Cyclone/separator efficiency For a given sorbent consumption one can get a higher efficiency of sulfur capture if the capture efficiency of the cyclone is improved [34] because of the increased mean residence time of particles in the CFB loop. Higher separation efficiency ensures sorbent particles are captured and sent to back to the combustor, thus improving the re-circulation rate, bed density and thereby sulfur capture. Improved separation efficiency ensures that even finest sizes are re-circulated. Reduced cyclone efficiency, on the other hand results in reduced suspension density of the upper furnace and reduced solid re-circulation rate. Since suspension density is the primary factor affecting the heat transfer coefficient [43], the heat absorption in the upper furnace reduces, increasing the furnace temperatures for a given fuel feed rate. If the furnace temperature exceeds the optimum temperature for sulfur capture, it will reduce the efficiency of sulfur capture and increase Ca/S ratio required to maintain a specified emission level. High Ca/S molar ration means increased limestone consumption, which leads to increased ash production and disposal cost. 1 Reactivity of sorbent is the reaction between substances, which can be monitored by some measure, either qualitative or quantitative (ASTM C51-11) [41]. 2 R is the reactivity of limestone. When multiplied by the total moles of calcium in the bed, gives the molar rate of sulfation of calcium or absorption of SO2 (since 1 mole of SO2 is absorbed by 1 mole of calcium oxide to form 1 mole of calcium sulfate) [16].

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6.2. NOx emissions

7. Loopseal malfunction

Nitrogen from atmospheric air and that bonded in fuel release thermal NOx and fuel NOx respectively [40]. The thermal NOx is formed at temperatures exceeding 1540 °C [17,44]. Since combustion temperatures in a CFB boiler are well below this temperature, thermal NOx is not a major component of its nitrogen oxide emissions. NOx emissions from CFB boilers are lower than those from PC fired boilers [17]. The important source of NOx emissions in coal and waste fuels that contain organically bonded nitrogen is fuel nitrogen-oxidation [45,46]. The NOx emissions can vary during boiler operation due to change in operational parameters such as combustion temperature, excess air coefficient, limestone feed rate and staging of combustion air. Effect of these operating parameters on NOx is discussed in Table 4.

One of the overlooked but key components of CFB boilers is loopseal. It received relatively scant attention in both industry and research though its operation exerts major influence on the output as well as on reliability of the boiler. The loop seal acts as an automatic control valve that regulates the recycled bed solids flowing back to the combustor. It serves as a pressure seal between positive pressure in the furnace and negative pressure in the cyclone. Loopseal being an intermediate component, is greatly affected by the efficiency of the cyclone as well as the operating conditions of the combustor. The loopseal related common problems are blockage/surging, plugging, agglomeration and gas refluxing. These operating problems are discussed in the following section.

6.3. CO emissions

7.1. Surging/blocking of loopseal

Carbon monoxide (CO) emission from a CFB boiler is generally very small. Yet, it is worthwhile examining how it is influenced by different operating parameters. Effect of operating parameters on CO is discussed in Table 5.

Use of bed materials finer than that specified by the boiler designer could increase the amount of entrained particles, which could in turn increase the recirculation rate. If the resulting recirculation rate exceeds the designed capacity of the loopseal, it can cause surging or blocking. Firing of a fuel containing ash much higher than that specified by the designer can also cause problems like surging in the loopseal especially if the loopseal was designed for low ash fuel. The ash content of coal varies greatly in some geographical regions. Firing coal with ash higher than its design value could result in decreased furnace temperature, higher bottom ash removal rate and overloading of loopseal/fluidized bed heat exchanger [52].

6.4. N2O emissions Nitrous Oxide (N2O) is a greenhouse gas, though NO2 and NO are not. When compared to carbon dioxide, it has 298 times higher ability to trap heat in the atmosphere [51]. The emissions of N2O are typically in the range of 50–200 ppm in coal fired fluidized bed boilers, but are only 1–20 ppm in pulverized coal fired boilers [51]. Effect of operating parameters N2O is discussed in Table 6.

Table 4 Effect of change in operating parameter on NOx emission. Parameter

Change in parameter

Effect on NOx emissions

Reference

Combustion temperature Excess air Limestone feed rate Ratio of secondary air to total combustion air Air staging height

Increase Increase Increase Increase Increase

Increase Increase Increase Decrease Decrease

[17,35,39] [30,35,37] [35,47,48] [49] [50]

Table 5 Effect of change in operating parameters on CO emission. Parameter

Change in parameter

Effect on CO emissions

Reference

Combustion temperature Excess air Gas residence time Soot blowing frequency

Increase Increase Increase Increase

Decrease Decrease till a minimum value and then begin to increase Decrease Decrease

[17,34] [50] [34] [34]

Table 6 Effect of change in operating parameters on N2O emission. Parameter

Change in parameter

Effect on N2O emissions

Reference

Combustion temperature Excess air Ratio of secondary air to total combustion air Air staging height

Increase Increase Increase Increase

Decrease Increase No significant change Decreases slightly

[39,51] [49] [49] [49]

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Fig. 2. Method to reduce amount of re-circulated ash [52].

A novel method to reduce solids load on the loopseal involves reduction in the cyclone’s collection efficiency. Here, low volume flow (1% of the total flue gas flow rate) of air jets are injected at a high velocity into the cyclone. It can ‘shoot’ ash particles from the cyclone walls into the gas outlet tube [52]. The gas-swirl inside the cyclone is not disturbed by this measure, and therefore the particle size distribution of the collected particles and of the circulating material does not change, but more particles escape the cyclone. Main design parameters that influences the cyclone efficiency are, location of nozzle, angle of injection, nozzle diameter. The first installation of this option was in a CFB boiler of RWE Power in Berrenrath in 2003 [52]. On implementation of this system the load on loopseal decreased but the fly ash collected in the ESP increased. Therefore, the ESP has to be designed for this excess load. The schematics of this system are provided in Fig. 2. 7.2. Agglomeration in loopseal Agglomeration of fluidized bed material in the loopseal is a source of potential problems and it could occur for certain types of fuels. Agglomerated solids can block the air distribution nozzles and de-fluidize the bed. Agglomeration could also occur due to insufficient air flow, uneven air distribution through the grid of the loopseal. Less than designed heat loss from the lower furnace or poor atomization of start-up oil gun [5], or pluggage of nozzles in some areas could also lead to agglomeration and or clinkering in the lower bed. Formation of agglomerates and some methods to reduce/prevent agglomeration are covered in Section 4.2.

Fig. 3. A typical loopseal in a CFB boiler.

can increase the transfer of bed material beyond its design limits and damage the expansion joint, whereas inadequate transfer leads to plugging of recycle chamber. 7.4. Gas back-flow Gas back-flow is the leakage of flue gases from the combustor into the loopseal and then into the cyclone. This could happen under one of the following situations [5]:
The materials column in the loopseal delivery section is too short to provide seal against the loopseal air and is blown through by the loopseal air.
Improper adjustment of the loopseal air, resulting in fluidization in the recycle chamber. To avoid gas refluxing it is necessary to do one of the following [5]:
Ensure an appropriate height of solids in the delivery column.
Stop the loopseal air flow until a certain amount of ash has accumulated in the supply chamber. 7.5. Special issues in petcoke fired boilers

7.3. Plugging of loopseal The fluidizing air distribution grid loop in a loopseal can experience plugging due to failed refractory pieces and/or slagging or blocking of the recycle section of loopseal [5] (see Fig. 3). Blocking of this section of the loopseal could be a result of higher than the designed value of ash content in the fuel, under-sized loop seal, insufficient fluidizing air supply rate and insufficient air velocities in the standpipe and in the furnace. Reduced recirculation of solids can cause lowered suspension density in the furnace leading to reduced heat transfer. Pluggage often goes undetected in a CFB boiler until a total outage occurs. Plugging can be detected by measuring the pressure drop across the loopseal. The amount of bed material recirculated through the loopseal is a function of the air velocity in the recycle section of a loopseal [53]. Excess fluidizing air velocity in the recycle section

Loopseals of boilers burning petroleum coke experience certain unique issues. The two issues are agglomeration in the loopseal and higher solid recirculation rate in case of boilers not designed to fire petcoke. The root cause for agglomeration is the presence of vanadium in petroleum coke and its oxidation to vanadium pentoxide (V2O5) during combustion. V2O5 has a very low melting point of 690 °C [54], which is below average combustor temperature. The chance of agglomeration is higher in the loopseal than in the combustor due to the low fluidizing air velocity. Higher than design solid recirculation rates are observed in boilers not originally designed to fire pet coke because of the addition of limestone as a sorbent. In order to avoid plugging of loopseal due to these higher than design recirculation rates only an optimum amount of petcoke can be co-fired. Adjusting the air flow to the loopseal also helps in avoiding plugging.

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8. Refractory related problems Refractory is a major maintenance item in a circulating fluidized bed (CFB) boiler, whose greater part of interior is lined with refractory (Fig. 4). The operating characteristics of CFBs require its refractory materials to withstand abrasion from circulating particles as large as 6 mm and thermal cycling along with temperatures in the range of 700–1000 °C [55]. The severe working conditions in a CFB furnace highlight the need for suitable refractory to avoid damage to boiler walls. The annual cost for refractory maintenance accounts for an average 25% of the total maintenance cost and can be as high as 40% [56]. Fig. 5 shows the relationship between total and refractory maintenance costs with respect to the capacity of the boiler. The annual maintenance costs are significant for large power boilers. However the maintenance cost per MW capacity per annum decrease with increasing thermal capacity. Refractory used in CFB boilers can be classified as pre-formed (brick, tiles, custom shapes), un-formed (castables, plastics, gun mixes) and special materials such as ceramic fibers [55]. Preformed refractories are shaped, dried and cured by the refractory manufacturer at their factory. Such refractory is ready to install on site. They are commonly available as bricks, but can be procured in custom shapes. The pre-forming and pre-curing makes it easy to assemble on site and saves time. Un-formed refractories are without definite form. They are formed to their respective shapes with the help of moulds by ramming or by gunning. Monolithic refractories are available in granular form, which need to be mixed with water before application. Plastic mixes are an exception. Plastics are available as pre-mixed mass, which can be applied directly by manual or pneumatic ramming. All monolithic refractories need

curing after application to drive out the moisture in a controlled manner. The un-formed refractory eliminates joints. Additionally has better spalling resistance and volume stability with ease in applying even in hot condition. Easy handling makes it better than formed refractory and, therefore is being widely used for CFB application. 8.1. Anchors The refractory material is generally held or anchored to the steel wall by means of anchors, which are held to the external steel walls either by welding or by means of fasteners. Anchors tend to keep the monolithic lining stable. The anchors, which are either metallic or ceramic, play an important role in the stability and life of the refractory. Poor anchorage can lead to failure of refractory lining. The cross section of a typical refractory lining used in areas requiring impact and erosion resistance is shown in Fig. 6. Refractory failure could lead to many operational problems, including:
Undesirable heat loss from the furnace.
Exposure of tubes and other pressure parts to the erosive and corrosive environment leading to tube failures, which is the most common reason for forced outages in a CFB boiler [58].
Failed refractory pieces may create obstruction to the flow of materials. For example, fallen refractory from the cyclone can obstruct the riser or loop seal [5].
Reduction in cyclone separation efficiency, which in turn adversely affects other operating parameters like sulfur capture efficiency [34].

Fig. 4. Wear resistant refractory usage in P–C Fired and CFB Boilers.

Fig. 5. Annual maintenance costs for refractories and for boiler plant in total, both in annual costs and related to boiler thermal power [56].

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is generally high in alkali content. For example, K, Na, Ca, and Mg compounds can be up to 40% by the weight of the ash, which could react with refractory materials [59]. At temperatures in the range of 760–1200 °C alkali can penetrate into refractory linings and condense in the pores and form alkali aluminum silicate, a lower density product. This reduction in density is accompanied by localized change in volume which leads to partial or complete refractory failure. At higher temperatures slag formation occurs, which steadily dissolves the refractory lining. Characteristics needed to resist alkali attack are low porosity, high density and purity and optimum chemistry. 8.3. Refractory failure The refractory failure can be classified on the basis of the cause such as, thermally induced failures, anchoring system failures, workmanship related failures.

Fig. 6. Cross section of refractory lining [57].

8.2. Refractory challenges in a CFB boiler Operating conditions in a CFB boiler are different from those in a conventional pulverized coal fired boiler. These differences are with respect to temperature, erosion and corrosion. Some of the challenges faced by specifically refractories in a CFB boiler are enlisted below. 8.2.1. Temperature Though, CFB boilers are characterized by low combustion temperatures of 850–900 °C, the upper furnace may experience high post combustion temperatures up to 1000 °C. The furnace temperatures may vary rapidly during load modulation or frequent startups giving rise to thermal shock. That thermal shock is harmful to the refractory. The lower furnace of a CFB operates in a reducing environment. To resist high temperatures the refractory needs to have high alumina content and high firing temperature. The characteristics needed to resist thermal shock are high strength, coarse grain size, moderate or high porosity and optimum coefficient of thermal expansion. 8.2.2. Erosion The internal walls of CFB boilers are prone to extensive wear due to the recirculation of bed particles that are up to 6 mm in size and moving at velocities up to 30 m/s. The refractory lining of the dense lower furnace and that of the dense external fluidized bed heat exchanger undergo abrasion. The upper part of the furnace and cyclone separator operates in relative dilute phase, but they also undergo severe erosion due to the high velocity and temperature of entrained particles. Erosive damage is a function of particle size and increase approximately with the cube of the velocity [55]. Characteristics needed to resist abrasion and erosion includes fine grain size, high density, high strength and low porosity. 8.2.3. Corrosion Besides coal a wide variety of fuels can be burnt in a CFB boiler. It includes difficult to burn wastes like refuse derived fuel (RDF), tire derived fuel (TDF) or biomass like straw. The ash of these fuels

8.3.1. Thermally induced failures Thermally induced failures are commonly found in castable and plastic monolithic refractories. The reasons for this failure are two phenomena called thermal cycling and thermal shock. Thermal cycling is disruptive due to the internal stresses resulting from different thermal expansion coefficient of the bonding agent and the aggregate. Thermal cycling typically results in large cracks and spalling of the lining as the small cracks fill with fluidized solids and exert compressive stresses on the hot face [55]. Thermal shock due to rapid temperature changes can cause spalling of the hot face on initial heat-up when the internal steam pressure exceeds the tensile strength of the material [55]. Thermally induced failures can cause partial or complete failure of the refractory lining. Some methods to avoid thermally induced failures are:
Specific heating and cooling curve provided by the Original Equipment Manufacturer (OEM) should be closely followed.
Adequate provision is needed for expansion and contraction. Control joints at suitable intervals should be provided in case of castable or plastic refractory surfaces to accommodate the expansion and shrinkage of refractory. They control and limit the cracks as they form a discontinuity in the surface.
Shrinkage factor, erosion resistance, compressive strength, thermal conductivities, and expansion differential between steel shell and various layers of refractories have to be considered carefully before application [55].
Stainless steel fibers and burn out fibers can be used to improve thermal shock resistance and reduce the possibility of explosive spalling [55]. It helps to re-distribute the crack pattern, from a few large cracks to many small ones. 8.3.2. Failure of anchoring system Anchoring system’s failures occur when the anchors holding the refractory to the walls, roofs, and tubes fail due to insufficient support. The reason for anchor failure could be improper anchor system design and its implementation. Good anchor system design involves proper shape of anchor, anchor material, anchor joint to surface and sufficient anchor density for the specified thickness of refractory lining. Some Methods to avoid anchoring system failures are:
Anchor design should be capable of resisting ‘pull-outs’. At the same time they should also be easy to remove without damaging nearby refractory in case of replacement. Simple ‘V’ shaped anchors with diameter less than 1/4th of an inch are easy to pull out without damaging nearby refractory. Bending the end of each leg by 60° or more creates a hook that can resist pull-outs until the castable or metal breaks.

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Anchor system must be fabricated from heat and corrosion resistant materials based on the operating temperature. For example, the critical temperature for plain carbon steels is 727 °C, so it cannot be used for CFB boilers as the operating temperatures exceed 800 °C.
Welding anchors to the wall is important. So, proper electrode selection and welding techniques are required to reduce anchor failure.
Sufficient number of anchors per unit area (anchor density) is necessary to sustain the weight of the refractory lining. A rule of thumb suggests the spacing the anchor 2–3 times the lining thickness for flat or nearly flat surfaces [55].
A recommended practice involves coating the anchor tips with mastic, tape, or other flammable material (wax or plastic covers) allow them to burn out during curing. So, it leaves room for expansion of the anchor as the lining heats up [55]. 8.3.3. Failures related to workmanship Poor workmanship may cause premature failure of refractory. They aggravate the thermally induced failures and anchoring system failure. 8.4. Initial curing/dry-out Unformed refractories (plastics, rammed, gunned and castables) are easy for application. Formed refractories (bricks and tiles) are already dried out in furnaces to specific shapes. They still contain small amounts of moisture absorbed during application, storage and transport while unformed refractories contain much higher amounts of moisture. This moisture needs to be evaporated in a controlled manner to avoid build-up of pressurized steam. Buildup of pressurized steam in refractories creates discontinuities and causes cracking and spalling. Improper dry out can cause partial or complete failure of refractories. With different types of refractories in various parts of the boiler, initial dry-out for each section is a challenge in CFB boilers. As mentioned earlier the curing/dry-out curve, provided by the manufacture for a refractory, should be strictly followed. The dry-out schedule is a function of the following [60]: (a) Quantity of moisture content in refractory (b) Material density and porosity (c) Heat capacity and thermal conductivity of the materials installed (d) Lining thickness and components (e) Location (walls, floors, side walls) Some important aspects to be considered during dry-out are:
The furnace must be under positive pressure to obtain a uniform heat distribution in all areas of the furnace [60].
Refractory should be heated by convection, as convection can convey heat to all corners and pores where radiant heat cannot reach.
Frequent air exchange under positive pressure is required to evacuate all the moisture drawn from the refractory lining. Air exchange rates need to be 20–30 times the volume of the component per hour [60].
The air circulated during dry-out should be clean and free of dust particles. Impurities in air react with the moisture and clog pores, restricting the escape of moisture.
The heating rates specified by the OEM should be adhered to.
The location of the burners/air-heaters plays an important role. Burners located too close to the refractory would dry the adjacent area pre-maturely making the region prone to failures [9].


Once heating has started it should not be interrupted until the process is complete.
The location of thermocouples play an important role in curing. It is advisable to place the thermocouples 1/200 (in.) above the lining [59].
Dry-out by slow firing the boiler should be avoided.
It is recommended to carry out the curing process under the supervision of experienced professionals [55]. 9. Tube failures Boiler tubes are subject to high pressure and temperature steam internally and high temperatures and flue gas flow externally. Tube failure is rated as the second most common cause of concern for boiler operating utilities [58]. Though conditions in a CFB boiler may seem to cause significant wear of some components of the boiler, the wastage rates do not exceed that of pulverized coal fired (PC) boilers [61]. Tube failures can be caused by mechanical wastage, corrosion or both. 9.1. Mechanical wastage/wear Three main mechanisms, namely, erosion, abrasion and fretting cause tube metal wastage [62]. Erosion involves the removal of metal from a surface due to the impact of particles. Abrasion involves the particles which are constrained in some way and mechanically loaded on the surface. Fretting can be defined as the wastage caused by the two solid surfaces being loaded against one another and having a small relative amplitude [62]. Mechanical wastage is influenced by factors such as hydrodynamics, ash properties, local flow of material and gas, proper design and workmanship [63]. The effect of particle shape, size and hardness is inconclusive and difficult to quantify [63,64]. Therefore, it can be assumed that the wear is primarily a function of the local material and gas flow conditions and boiler design. The rate of wastage is enhanced by poor design, irregularities in structures and poor choice of materials. In a CFB boiler any unnecessary discontinuities in vertical water walls that would change the direction of downward and upward flowing particles increase metal wastage and should be eliminated [9]. Such discontinuities may arise due to excess weld material or incomplete welding of water walls. Erosion protection should be provided wherever discontinuities are unavoidable. The mechanical wastage associated with different areas in a CFB boiler is discussed in the following sections. 9.1.1. Interface between refractory lining and waterwall The lower furnace of a CFB boiler is refractory lined up to a certain height to avoid excessive abrasion and corrosion of water wall (Fig. 7). The interface between refractory lining and the exposed water wall is prone to extensive wear. The wear in this region is attributed to the dense stream of downward flowing solids or formation of a vortex as illustrated in Fig. 8. Basu [39] provides an alternative explanation using two body erosion principle. The downward flow of dense solid flow causes erosion of the tube as well as refractory material. The rate of erosion is also affected by the solid refluxing rate in the furnace. Modification in the other regions in the boiler affects the hydrodynamics and in turn affects the rate of erosion. The Pyropower unit at Chatham, Canada originally ran initially for considerable time with no detectable wear. However, after 1100 h, very severe tube loss was observed. The reason for this severe loss was found out to be due to a modification made to reduce the cross sectional area of the inlet duct to the cyclone. The intent was to increase the velocity of particle entering the cyclone, but it in turn also increased the amount of solids refluxed [63] and hence increased solid down flow along the wall.

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Fig. 7. Refractory-Waterwall interface [65].

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Fig. 9. Step formation due to erosion attack [65].


Weld overlay Weld overlay of wear-resistant material on tubes acts as a sacrificial layer. The rough surface caused by welding accelerates wear and should be smoothed after application [65]. The overlay extends about 100 mm above the tapered refractory as shown in Fig. 10.
Kick-out design

Fig. 8. Local vortex formation at refractory-waterwall interface (adapted from [62]).

An innovative way to avoid the refractory step at waterwall interface is to incorporate a kick-out design. This involves bending the lower part of the tubes outwards, so that the refractory lining of the lower section is coplanar with the upper unlined water wall [67]. This method to avoid discontinuities eliminates the need for any special erosion protection. The representation of the basic kick out design is illustrated in Fig. 11 and an actual interface with kick out tubes is shown in Fig. 12, where no discontinuity is observed in the downward flow of solids.
Increasing the height of refractory lining

It is interesting that the erosivity of ashes retrieved from biomass fired boilers is found to be higher than coal fired boilers due to the presence of chemically active compounds [64]. Methods to Protect/Prevent Wear at Refractory – Waterwall Interface
Wear resistant coatings Wear resistant coatings does not prevent erosion but delays tube failure. It has been used with limited success in the refractory water wall interface region. Spray coatings are characterized by [66]:





Particle density in the furnace decreases with increasing height [68]. It has been observed that boilers with interface higher up in the lower density region, have reduced wastage [63]. Thus, increasing the height of refractory termination up to a lower particle density region can be an effective method to reduce wastage. But the covering a greater area by refractory leads to reduced heat absorption in the furnace.

Surface structure and roughness Macrostructure and microstructure of the coating Bond to substrate material/adhesion medium Expected resistance to wear and corrosion

Some common spray coatings available are NiCrBSi, CoCrNi, NiCr/Cr2C3. These coatings are applied by flame spray coating with wire or powder, arc spray coating process, high velocity oxy-fuel spray process or plasma process. As per tests carried out in Bayer Industry Services, Leverkusen, the NiCr/Cr2C3 coatings performed better than the others over a period of 12 months [64,66]. The reason for limited success of spray coatings in the interface region is the formation of a step that grows deeper with erosion attack [65]. This process of step formation and erosion is shown in Fig. 9. It is interesting to note here that the erosion occurs by the same mechanism as that for the tube refractory interface.

Fig. 10. Weld overlay at interface [63].

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Fig. 13. Erosion of corner tubes [65]. Fig. 11. Interface without and with kick-out design.

Fig. 14. Application of refractory to first corner tubes [65].

Fig. 12. Kick-out design in an actual CFB furnace [65].


Shelves Lateral shelves are welded higher up on the water walls to reduce the rate of erosion. The method attempts to reduce both, thickness and velocity of the solid layer sliding down the wall. Welding a shelf allows dust to collect and create its own angle of repose [62]. 9.1.2. Corners formed by water-wall panels Water-wall joints at corners are particularly vulnerable to erosion. So lining of the corners with ramming mass is required to avoid erosion of the first tube each near the corner. Fig. 13 shows the erosion caused at the first tube near each corner, Fig. 14 and Fig. 15 show the applied ramming mass on the corner tubes.

Fig. 15. Ash cone at refractory corner and interface [65].

9.1.3. Suspended heat transfer surfaces Suspended heat transfer surfaces are added inside the furnace and back pass of boilers for increased in furnace heat absorption. Typical designs are pendant panels, omega tube panels and wing walls. Pendant panels are roof supported heat transfer surfaces located in horizontal crossover ducts connecting the furnace and the backpass. Wing walls (shown in Fig. 16) are located in the furnace and supported at the roof and at the waterwalls. Wear is

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releasing them as alkali chlorides and hydroxides in gas phase [46]. In biomass-fired boilers, the most severe corrosion problems are associated with deposits containing alkali chlorides [70]. Some methods which can reduce this corrosion are listed below:

Fig. 16. Refractory application on wing walls to reduce wear.

observed either at the corners formed with the furnace waterwalls, the bottom surface or both these areas [62]. To reduce wear on the bottom surface, refractory is applied at the bottom portion of the wingwalls that run perpendicular to the flow of bed particles, as shown in Fig. 16 [9]. The refractory is held with the help of studs welded to the tubes. 9.1.4. Fluidized bed heat exchangers (FBHE) In some boiler designs, FBHE’s may be located in the loopseals. The tubes of these heat exchangers are refractory lined to protect them against erosion. INTREXTM heat exchanger is a patented design of Foster Wheeler that uses and internal bubbling fluidized bed to receive hot solids from either the furnace or the loopseal. Other companies use an external fluidized bed heat exchanger for the same purpose. The fluidizing velocity is very low (below 1 m/s) and therefore the risk of erosion is minimal [19]. Fretting has been observed between tubes and tube supports [68,69]. Rigid tube support and due consideration for thermal expansion of the complex tube structure can reduce potential of tube failure in FBHE. 9.2. Gas side corrosion Corrosion can be defined as the deterioration of intrinsic properties of a material due to reaction with its environment [46]. It can be caused by reaction of gas phase species, on metals or deposits or by a combination of both [70]. Sulfur, vanadium, chlorine and alkali metals are responsible for gas side corrosion. Sulfur in flue gas causes the sulfation of Fe, Ni, Cr present in the tube material, which results in formation of sulfates/sulfites [71]. Vanadium compounds in the flue gas react with the oxide/sulfate scales on the metal and increase rate of corrosion [71]. In case of biomass fired boilers the alkali metals, sodium and potassium form deposits on heat exchanger surfaces. Deposits reduce the rate of heat transfer and thereby affect the boiler capacity. To avoid this, soot blowers are used to remove the deposits at regular intervals. Though these deposits themselves do not harm the tube material, it is their complex reactions with chlorine, sulfur and silicon that causes corrosion. Chlorine molecules diffuse through the protective oxide layer and form metal chlorides, which corrode tubes [70]. Chlorine increases volatility of alkali metals,


Since the rate of corrosion is higher at higher temperatures, maintaining optimum design temperatures in respective parts of the boiler can effectively control the corrosion [72].
Use of bed additives such as bauxite, kaolinite and limestone produce alkali compounds with a high melting point relative to alkali chlorides [46]. These compounds with relatively higher melting temperatures reduce the rate of corrosive alkali chloride deposit formation.
The boiler can be fired with chlorine free fuel for a short period of time during start up after a boiler cleaning. This allows for an oxide layer to form on the heat transfer surfaces. This oxide layer protects the metal surface up to some degree when fuel with chlorine content is fired [72].
To avoid corrosion in the superheater region the metal temperature should be low. So the outlet steam temperature has to be kept below a permissible limit for the specific fuel. Alternatively, suitable corrosion resistant alloy steels have to be used [70].
For fuel containing chlorine, sulfur may be added in some form because, sulfur preferentially forms alkali sulfate, allowing chlorine to remain in gas phase and leave the boiler without being deposited [73] to cause corrosion. 10. Bed nozzle issues The air distributor nozzle on the grate of a CFB boiler is an extremely important element, as its operation affects various parameters of the boiler. Typical problems of nozzles are blockage, slagging, erosion, caps coming off and slag leakage [5]. Nozzles of similar design and materials have shown varying rate of failure in different boilers. Two major reasons for nozzle replacement are erosion and corrosion. 10.1. Design factors Some important factors affecting the lifespan of nozzles are discussed below. 10.1.1. Operational characteristics Parameters such as temperature, pressure drop, air flow and orifice velocity affect the operational life of the nozzles. Excess the velocity leads to increased turbulence and wear of nozzles due to erosion. The pressure drop across a nozzle, however, should be high enough to avoid plugging and back shifting. 10.1.2. Fuel characteristics The fuel and bed material characteristics can also affect the life span of nozzles. High alkali containing fuels corrode the nozzles. Choice of materials for construction of nozzles should also consider the chemical composition of the fuel. 10.1.3. Location of nozzle Nozzle situated near the loop seal return and fuel feed ports face a higher risk of wear [5]. The nozzles situated near the loop seal return are much more prone to wear, than those near fuel feeding ports due to the presence of significantly higher amount of circulating ash flow rates. Not only erosive but even corrosive wear is noticed in these regions due to localized combustion and presence of chemically active ash particles. Raising position of the inlet with respect to the air distributor grid, changing angle

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Fig. 17. Furnace cross section area with severe nozzle erosion (Adapted from [5]).

of inlet, use of multiple recycle ports to reduce flow through a single port and introducing additional fluidizing air at loopseal inlet to furnace to improve distribution of solids in the recycle stream are some remedial measures which can be applied to reduce localized wear of nozzles [62]. The area in the furnace with frequent need for nozzle replacement is shown in Fig. 17.

because the boiler load is dependent on air flow rate through the nozzles. It is also caused due to un-even distribution of fluidizing air [75]. Primary air could pick up solids from the floor of the windbox, and pass through nozzle orifices at very high velocity (60 m/s) eroding the nozzles. Some methods to prevent/reduce back sifting are:

10.1.4. Deflection The most common reason for wear is erosion by the air jetting out from an adjacent nozzle. High velocity particles in the bed rapidly erode the nozzles and riser pipes under such conditions. For easy removal of the coarse material in the bed that can wedge between nozzles, a stepped distribution grid is effective [19].


Check for the adequate pressure drop through the grid and nozzles, fan capacity and velocity at outlet of fan [75].
Nozzles with orifices enlarged due to erosion should be replaced to maintain the required pressure drop and air velocity [75].
If nozzle orifices are dimensionally correct, then the other option is to blank a specified number of nozzles in order to raise pressure drop to the required level [75]. The position of nozzles to be blanked should be selected such that there is uniform fluidization throughout the bed.
The wind box should be checked for leakages if the back sifting is observed in a particular area of bed [75].
It is advisable to add sight glasses or windows in the wind box or plenum chamber to observe the nature of back sifting. Adding an ash drain at a suitable location to the wind box or plenum could facilitate removing back shifted ash during boiler operation.

10.2. Operational factors 10.2.1. Erosion of nozzles The direction of nozzles plays an important role in avoiding formation of vortexes and turbulence. For nozzle located near the wall vortexes and turbulences cause localized wear. In some cases severe wear in the nozzle located in the corners of the furnace is observed. A refractory step created along the perimeter of the furnace disrupts the solid flow and reduces the problem of erosion nozzles [74]. Newer generation of nozzles that direct jets away from neighboring nozzles also reduces erosion. 10.2.2. Enlargement of orifices Erosion could enlarge the size of the orifice after certain time of operation. Enlargement of orifices reduces the orifice velocity and therefore pressure drop, which leads to back-shifting of solids into the wind box [62]. It is advisable to measure the orifice of some nozzles in various areas of the furnace after a boiler shut down. Nozzles should be replaced if the change in orifice dimension is beyond acceptable limits. 10.2.3. Back-sifting As mentioned earlier ash and bed material at times back-flow through the orifice into the windbox. It is called as back sifting. The bed material settles in the windbox and causes obstruction to the primary air flow. Back sifting of material is the result of insufficient pressure drop among other factors [75]. Lower boiler load corresponds to lower air flow rate and therefore lower pressure drop through the grid. Back sifting is common in CFB boilers

11. Expansion joint failure Expansion joints in a boiler compensate for the vibration and thermal expansion of in air flue gas duct systems. Expansion joints require more attention in case CFB boilers, because some of them are located in ducts carrying not only flue gas but also hot bed material. These expansion joints are prone to failures due to the penetration of dust into the seal, or condensate corrosion [62,76]. Inner pressure in the duct of a CFB boiler is higher than that of a PC boiler and may be as high as 40 kPa in some components [32]. With such high pressure, those expansion joints whose compression strength is inadequate will probably fail after a short operation period and thereby severely affecting operation of the boiler [32]. During start-up the expansion joints is subjected to rapid temperature changes in the joint connecting the primary air duct and wind box (only in case of in duct burners) resulting in tear due to uneven expansion [5]. Increasing numbers of modern CFB boiler are using loopseal to supplement fuel feeding into the boiler. It

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dling increased bottom ash production in case of high ash content in coal or coarse particle size of fuel and bed material [17]. The following sections study the problems related with commonly used ash coolers. There are four main types of ash coolers: (a) (b) (c) (d)

Fluidized bed Screw type Air cooled (Belt) type Rotary (drum) type

12.1. Fluidized Bed Ash Coolers Fluidized Bed Ash Cooler (FBAC) is essentially a bubbling fluidized bed with immersed heat transfer tube bundles, which is especially good for burning high ash coal [9]. Large volume of ash with oversized particles may cause ash to build up on the tube bundles in the coolers, thereby lowering heat exchanger capacity and increasing the ash discharge temperature [77]. It is difficult to modulate the ash flow rate in case of ash production quantities higher than the design values. Choking of FBAC duct is common for fuels with ash content higher than its design value. Some methods to prevent choking are mentioned below.

Fig. 18. Location of expansion joints on return leg of loopseal.

promotes better mixing and provides longer residence time to fuels. In this design, a part of the fuel is fed through the return leg (delivery pipe) of the loopseal as shown in Fig. 18. As soon as fresh fuel particles enter the pipe it mixes with the large volume of hot solid being conveyed through the pipe. This gives rise to rapid heating and release of volatile gases. Owing to this release of volatiles and its expansion at high temperature in the delivery pipe there is an increase of internal pressure in the recycle pipe. In some cases the combination of high temperature and high pressure can cause the failure of non-mechanical expansion joints located in the delivery pipe. Best option to avoid this problem is to move the feed point as far away as possible from the expansion joint towards the inlet of the furnace. Methods to Protect and Prolong the Life of Expansion Joints:
Periodic maintenance of fabric expansion joints helps detect minor leakages and damage to the insulating material between fabric and liners.
Deterioration of the fabric cover rubber can be avoided by painting it with Chloroprene/Hypalon based paint, thus ensuring longer life of the fabric expansion joints.
Expansion joints must generally be protected with appropriate covers (e.g. fire blankets, steel sheets) against damage during welding, cutting, grinding, insulation or painting work carried out in the vicinity. These covers should be removed prior to commissioning.
Qualified professional help should be sought for installation and un-installation of the expansion joint.


Removing some ash cooling coils in the bed helps improve ash flow through the cooler [9].
Installing distribution plates inside ash coolers helps direct ash flow in the desired direction [9].
Improvements of auxiliary equipment of the FBAC such as, expansion joints on ash conveyors, drag chain and bucket elevator conveyor attachments are necessary to accommodate the increased ash flow through the ash cooler [9].
Bottom ash crushers can be installed at the inlet of the FBAC to reduce size of coarse particles [9]. 12.2. Screw ash cooler Screw ash coolers convey ash through a water jacketed trough with the help of hollow flights on a hollow shaft. Cooling water is circulated through the trough, hollow shaft and flight arrangement. A typical arrangement is shown in Fig. 19. These systems face excessive wear due to relative motion between ash and conveyor parts [78]. Deposition of ash on screw flights reduces heat transfer between cooling water and ash. Higher operating costs due to the requirement of softened cooling water is a major limitation of screw ash cooler. Some methods to reduce wear in screw ash coolers
The wear on the front end of the screw flights at inlet can be reduced by adding sacrificial wear strips on flights [79].
Replace the hollow flights in the inlet section by solid stainless steel flights with weld overlay.
Wear at the feed end is due to stagnation of ash and, it can be reduced by using ‘rifle bars’ at the trough bottom [79]. 12.3. Air cooled ash cooler

12. Ash coolers Ash coolers in a CFB boiler provide safe and effective means of drainage of coarse ash from the bed. To maintain a constant bed inventory the bottom ash is continuously drained in a CFB boiler operated at constant load. Fuel feed rate and ash removal rate are two parameters used to control the solid inventory of the dense bed. The drained ash comes out at the bed temperature. Ash cooler cools down the coarse and fine hot bed material and return the fines to the bed. Ash cooling mechanisms must be capable of han-

Here, ash drained from the bed is conveyed on a steel mesh belt to the downstream equipment while cooling air passes through the system. Due to the absence of abrasion between the ash and the equipment the only wear observed is in the belt assembly. General arrangement of the air cooled ash cooler is shown in Fig. 20. This system does not need water, water treatment equipment and complex water tight assemblies [80]. It totally eliminates all water related problems like corrosion, leakage, etc. The unburnt combustibles in the ash at outlet is lower than other comparable

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Fig. 19. General arrangement of screw ash coolers.

Fig. 20. General arrangement of air cooled ash coolers.

systems when hot air carrying unburnt carbon is blow back into the bed [80]. The quantity of ash passing through the equipment can be changed by varying the belt speed. The equipment is however bulky and initial investment is high for these systems [5]. 12.4. Rotary ash cooler The rotary ash coolers work like a reverse kiln [77] where solids enter at one end of a rotating barrel and are cooled by spiral and longitudinal fins inside the barrel as they are transported to the other end. The barrel is jacketed with cooling water circulating within. The ash handling capacity can be varied by increasing the rotational speed of the barrel [81] and the thermal capacity can be increased by increasing the length of the barrel [77]. These systems are insensitive to the quality and size distribution of ash particles [5]. Many CFB plants are using it to replace FBAC systems [81].


Ensuring quality)
Ensuring
Ensuring
Ensuring

system function (availability, efficiency and product system life safety human well-being

There are many maintenance strategies described in literature, which have overlapping definitions and functions. The two most basic maintenance strategies are reactive and proactive maintenance classified depending on whether the required action to counter failure is taken before (proactive) or after (reactive) the actual failure occurs. They are limited to the role of fulfilling the above four objectives. Maintenance strategies have advanced over a period of time to adapt to the numerous process and product requirements. Advanced maintenance strategies, like total productive maintenance, are aimed at not only avoiding failure of equipment but also waste reduction, information gathering and analysis [83], improving productivity and design of equipment [84].

13. Maintenance of CFB boilers 13.1. Reactive maintenance (breakdown maintenance) Maintenance is the upkeep of equipment to ensure its safe operation within a specified range of parameters. The four main objectives of maintenance are [82]:

Reactive maintenance strategy is based on implementing necessary remedies to return the failed component to normal operating

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condition. It is carried out in case of a component failure. Component failures can be unpredictable in the absence of a preventive maintenance strategy. Thus it is of utmost importance to carry out breakdown maintenance in a time bound manner in order to maintain availability of the boiler. Tube failures, refractory failure in particular cases, agglomeration and loopseal de-fluidization are some common instances in which reactive maintenance has to be initiated. 13.2. Proactive maintenance Proactive maintenance can be explained as the strategy to avoid equipment failure by means of preventive maintenance methods that are either time based (periodic/scheduled) or conditions based (predictive). TPM consists of preventive and predictive maintenance [84]. Preventive maintenance estimates the probability of failure in a specific interval [84] and initiates necessary action. Predictive maintenance makes use of instrumentation to measure physical parameters like, temperature, pressure, etc. and suitable action is carried out based on the condition. It is also called as condition based maintenance [84]. Some proactive maintenance procedures specific to CFB boilers are discussed in the following sections. 13.2.1. Fluidization uniformity test Bed material is fluidized in the cold condition until stable fluidization is attained. The primary air fan is then switched off and the particles are allowed to settle naturally [32]. The state of the bed material thereafter indicates the quality of fluidization. Uniformly settled bed material forming a flat bed surface indicate constant pressure drop across the cross sectional area of the bed. This test is only suitable for multi-directional (multi orifice) nozzles. 13.2.2. Particle size distribution monitoring Particle size of bed material affects various operating parameters of a CFB boiler, such as, heat absorption, combustion efficiency, emissions, cyclone efficiency and bed temperature [42]. So, it is necessary to continuously monitor the size distribution of bed material. This is generally done by sieving the bottom ash. Online estimation of grain size is also possible using modern camera systems which track the grain size variation [42]. In order to maintain particle size the sieves/screens on the fuel and limestone crushers should be periodically calibrated and should be replaced if necessary [36]. 13.2.3. Pressure drop test of distributor nozzle The pressure drop across the distributor nozzles of the furnace is an important factor affecting the hydrodynamics and operation of the CFB boiler. A decrease in pressure drop can be observed due to erosion of nozzle orifice or leakage in the wind box and can lead to back sifting of bed material. It is essential to conduct the pressure drop test across nozzles during every planned outage. A loss of pressure drop prompts the maintenance teams to check the wind box for leakage and check the nozzle orifice diameter. Since the number of nozzles is large, random samples can be checked. Higher probability of nozzle erosion is observed in nozzles present in front of the fuel feed and bed material return ports [5]. 13.2.4. Fluidized bed pressure drop test The pressure drop across the fluidized bed is an important parameter of a CFB boiler as it directly affects the suspension density of upper furnace, the heat transfer coefficient, amount of carbon lost in fly ash and auxiliary power consumption [85]. Increase in pressure drop suggests an increase in solid suspension

Fig. 21. Relationship between carbon lost in fly ash, particle residence time, oxygen distribution and solid density [85].

density in the furnace. Higher solid concentration promotes residence time of the particle by enhanced cluster formation and dispersion [85] but, higher solid suspension density can inhibit gas solid mixing and cause varying lateral oxygen distribution in the furnace. Fig. 21 explains this relation between particle residence time, oxygen distribution, carbon lost in fly ash and solid density. The pressure drop across the bed should be monitored regularly and an optimal value should be maintained, which helps maintain gas residence time and allow uniform oxygen distribution (see Fig. 21). 13.2.5. Monitoring pressure drop across furnace and cyclone Like the pressure drop across the length of the furnace, the pressure drop across the cyclone is also directly proportional to the solid suspension density (solid concentration) at a constant gas velocity [86]. Pressure drop higher than the design value could be caused by particle size lower than that recommended. A higher-pressure drop results in high auxiliary power consumption. A lower solid suspension density on the other hand reduces the heat transfer co-efficient between the gas-solid phase and heat transfer surfaces located in freeboard, water/steam cooled cyclone or both. Monitoring the pressure drop across the length of the furnace and across the cyclone, signal a change in the rate of heat transfer and a change in particle size distribution. 13.2.6. Cyclone temperature rise (post combustion) Rise in flue gas temperature across the inlet and outlet of the cyclone is due to post combustion of fuel particles in the cyclone. Post combustion is more prevalent in hot cyclones, without water/steam cooling. The rise in temperature, which is generally in the range of 30–50 °C, disturbs the heat balance between various heat transfer surfaces in the boiler [87]. The post combustion is affected by the particle size distribution and the volatile matter content of the fuel. Fuel particles finer than the design size leads to the entrainment and post combustion in the cyclone. Lower volatile matter content than the design value in fuel also promotes post combustion. This is because a fuel with lower volatile matter content is generally less reactive and the height of the furnace is not sufficient for complete combustion of combustibles. Thus, combustion takes place in the cyclone and a rise in temperature observed. It is advisable to maintain the fuel particle size distribution and fuel volatile matter content within design limits to avoid temperature rise in cyclone.

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13.2.7. Online sampling of solids from loopseal for size distribution analysis Ash retrieved from the bottom ash drain include both coarse and fine particles of the bed material. On the other hand, samples of solid particle retrieved from the loopseal represent only the fine recirculating particles. Analyzing these samples provides useful information about the defragmentation of bed material, combustion efficiency and separator efficiency.

14. Conclusion Interest in the use of circulating fluidized bed boilers is rising fast especially in emerging economies. Its potential for reliable operation with difficult-to-burn fuels like petcoke, waste and biomass made it attractive to large number of industries ranging from small process plants to very large utility companies. Much research on advanced topics of combustion, emission and hydrodynamics has been conducted, but very little is available on real life operation and maintenance issues of CFB boilers. This review provides an overview of this topic giving an insight into some of those issues. The operation and maintenance (O&M) issues has been classified into the following topics: 1. 2. 3. 4.

Safety issues Operational problems Boiler component failures Maintenance issues It was noted that:

1. Although CFB boiler is intrinsically safer than conventional PC boiler there are certain areas of special safety concern. They need to be addressed adequately. 2. Bed material is often taken for granted for CFB operation, but it could exert major influence on the operation of the boilers and could be a major cause of reduction in its performance and even boiler failure. So, maintenance of right size distribution and property is important. 3. High bed temperature proved to be a common problem in CFB boilers around the world with some adverse effects on the performance, reliability, and material life other boiler. This can be addressed ensuring adequate heat absorption in the furnace. 4. Loopseal is like the heart of a CFB boiler. Even a brief outage of loopseal can stop a boiler. Compared to other component its operation is less understood, but industries have developed some practical options for addressing the failure of loopseals. 5. Refractory is a major problem in CFB boilers. Improper selection, improper application are two major contributors to its failure. Operation methods have made less contribution to its failure. 6. Tube erosion and to a lesser degree corrosion make major contribution to forced outage of CFB boiler. Proper design and operation can reduce the incidence of tube failure. Finally, a proactive preventive maintenance could greatly improve the availability of the boiler and reduce forced outage. References [1] R. Giglio, The Value Proposition of Circulating Fluidized Bed Technology for the Utility Power Sector, PowerGen Asia 2013, Bangkok, Thailand, 2–4 October 2013. . [2] International Energy Agency [IEA], Fluidized Bed Conversion 2014. [3] Environmental Protection Agency [EPA], Memorandum: Startup and Shutdown Provisions 2012.

[4] M.A. Friedman, T.J. Heller, T.J. Boyd, Operational data from 110 MWe Nucla CFB, Proceedings of the 11th International Conference on Fluidized Bed Combustion, Montreal, Canada, 21–24 April 1991, pp. 381–390. [5] L. Cheng, J. Zhang, Z. Luo, K. Cen, Problems with circulating fluidized beds in China and their solutions, VGB Power-Tech Congress, Bern, Switzerland, 21–23 September, 2011, pp. 60–69. [6] A.N. Tugov, G.A. Ryabov, E.P. Dik, D.S. Litoun, O.M. Folomeev, S.G. Sthalman, Operating experience of fluidized bed furnaces of municipal wastes incineration of rednevo plant in Russia, in: Proceedings of the 9th International Conference on Circulating Fluidized Beds, Hamburg, 2008, pp. 1063–1068. [7] P. Basu, A. Ghosh, An experimental investigation into the over bed start-up of a fluidized bed boiler, in: Proceedings of the 19th International Conference on Fluidized Bed Combustion, Vienna, Austria, 21–24 May, 2006, p. E-71. [8] Q. Guo, X.S. Zheng, Q. Zhou, L. Nie, T.S. Liu, X.K. Hu, J.F. Lu, Operation experience and performance of the first 300 MWe CFB boiler developed by DBC in China, in: Proceedings of the 20th International Conference on Fluidized Bed Combustion, China, 18–21 May, 2009, pp. 237–242. [9] W. Nowak, Z. Bis, Experience gained during operation of 235 MW CFB boilers at turow power plant, in: Proceedings of the 7th International Conference on Circulating Fluidized Beds, Niagara, USA, May 2002, pp. 621–628. [10] National Fire Protection Association [NFPA], NFPA 921, Guide for Fire and Explosion Investigations, National Fire Protection Association, Batterymarch Park, Quincy, MA, 2004. . [11] National Fire Protection Association [NFPA], Report of Committee on Boiler Furnace Explosions, National Fire Protection Association, Batterymarch Park, Quincy, MA, 1988. . [12] J.Y. Hristov, Fluidized Bed Combustion as a Risk-Related Technology: A Scope, in: 3rd South-East Symposium on Fluidization, Romania, 2001. . [13] S. Cooper, Explosion venting: the predicted effects of inertia, in: Institution of Chemical Engineers Symposium No. 144, 1998. . [14] K. Rayaprolu, Boilers: A Practical Reference, CRC Press, 2013. [15] National Fire Protection Association [NFPA], NFPA 654: Standard for the Prevention of Fire and Dust Explosions from the Manufacturing, Processing, and Handling of Combustible Particulate Solids, National Fire Protection Association, Batterymarch Park, Quincy, MA, 2006. [16] R.K. Eckhoff, Dust explosion prevention and mitigation, status and developments in basic knowledge and in practical applications, Int. J. Chem. Eng. 2009 (2009). 569825. [17] P. Basu, Combustion and Gasification in Fluidized Beds, CRC Press, 2006. [18] National Fire Protection Association [NFPA], NFPA 85: Boiler and Combustion Systems Hazard Code, National Fire Protection Association, Batterymarch Park, Quincy, MA, 2011. [19] P. Makkonen, Control of Wear in Fluidized Combustion Applications, ASME Seminar in Tampere, Finland, 2001. [20] J. Kovács, What is Fluidised Bed Agglomeration? IFRF Online Combustion Handbook, 2003, ISSN 1607-9116, . [21] M. Ohman, A. Nordin, Bengt-Johan Skrifvars, R. Backman, M. Hupa, Bed agglomeration characteristics during fluidized bed combustion of biomass fuels, Energy Fuels 14 (2000) 169–178. [22] W. Lin, A.D. Jensen, J.E. Johnson, Dam-Johansen Kim, Combustion of biomass in fluidized beds-problems and some solutions based on danish experiences, in: Proceedings of the 17th International Conference on Fluidized Bed Combustion, Jacksonville, USA, 18–21 May, 2001, pp. 892–900. [23] E.J. Anthony, L. Jia, F. Preto, J.R. Iribarne, Agglomeration and fouling in petroleum coke-fired boiler, in: Proceedings of the 14th International Conference on Fluidized Bed Combustion, Canada, 1997, pp. 839–846. [24] J. Ruud van Ommen, M. Bartels, J. Lensselink, F. Kleijn van Willigen, Willem van de Kamp, J. Nijenhui, Early agglomeration recognition system (ears): monitoring industrial circulating fluidized bed conversion, in: Proceedings of the 9th International Conference on Circulating Fluidized Beds, Hamburg, Germany, 13–16 May 2008. . [25] M.R. Kim, J.K. Lee, Prevention of bed agglomeration with iron oxide during fluidized bed incineration, Korean J. Chem. Eng. 26 (5) (2009) 1399–1404. . [26] M.D. Mann, Agglomeration mechanisms and mitigating measures in fluid-bed combustion, in: Proceedings of the 7th International Conference on Circulating Fluidized Beds, Canada, 2002, pp. 645–652. [27] B.D. Grubor, S.N. Oka, M.S. Ilic, D.V. Dakic, B.T. Arsic, Biomass FBC combustion – bed agglomeration problems, in: Proceedings of the 13th International Conference on Fluidized Bed Combustion, United States, 1995, pp. 515–522. [28] V. Mettanant, P. Basu, J. Butler, Agglomeration of biomass fired fluidized bed gasifier and combustor, Can. J. Chem. Eng. 87 (5) (2009). . [29] W. Lin, G. Krusholm, K. Dam-Johansen, E. Musahl, L. Bank, Agglomeration phenomena in fluidized bed combustion of straw, in: Proceedings of the 14th

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