Natural Gas Co-firing Research Articles

Multi-mode combustion facility for thermal treatment studies of wastes and biomass

This article describes newly built Multi-Mode Combustion Facility (MCF) used for investigating thermal destruction of industrial wastes and combustion of biomass. A flexible, refractory-lined combustion chamber consists of individual sections of various heights and diameter of 0.5 m. The MCF can be used either as a fluidized bed combustor (FBC) to study the combustion of solid residues or as a single-burner furnace (SBF) to study cofiring of biomass and natural gas. The facility is designed such that the outer wall temperature should not exceed 327 K with the use of water-cooling system and refractory materials. The inner temperature of each section is independent of the rest of the sections and controlled individually. This arrangement allows for the combustion process to be carried out in a multizone manner called low–high–low (LHL) temperature approach. The LHL approach means that the waste/biomass is initially fed into a low temperature zone (<1060 K) and then subjected to the high temperature treatment (∼1500 K) that is followed by another low temperature zone (<1160 K). The LHL setup allows for heavy metals encapsulation and immobilization within the fly ash particles. The facility has 25 openings for sampling of solids and gases at different stages of the combustion process, as well as in situ observation. Experiments reported in this article were performed in the bubbling FBC mode with the purpose of testing the leachability of heavy metals (Cd, Cr, and Pb) from fly ash generated during two different combustion approaches: (1) multi-zone LHL treatment, and (2) no-LHL. Baseline fluidization properties of different bed materials were tested. Axial profiles of temperature and gas concentration (CO2, NO, and NOx) were compared. The results show that the leachability of the heavy metals (Cd, Cr, and Pb) contained in the LHL-generated ash particles was negligible (0.14, 0.061, and 1.55 ppm, respectively), while the leachability data from the no-LHL technique were 30.7, 14.3, and 0.647 ppm, respectively. It was concluded that the MCF facility is easy to operate, flexible, and useful for studies of various waste-to-energy options. Our results also show an improvement in heavy metals leachability when using the LHL combustion technique.

A Unified Biomass-Coal Pyrolysis Reaction Model

A unified first order reaction rate model of pyrolysis is presented to facilitate co-utilization of domestic fuels (CDF) spanning the entire coalification region. This model was first used in interpretations of University of Florida laboratory and industrial scale coal-natural gas (C-NG) co-firing experiments using reaction rates based upon coal pyrolysis yields measured at MIT. After undertaking industrial-scale municipal solid waste, biomass, coal, and natural gas co-firing experiments, the pyrolysis model was used to interpret experiments with these fuels. The model is here adapted to represent ultra pyrolysis (UP) yields of cellulose measured at the University of Western Ontario (UWO) and fast pyrolysis (FP) yields of eight coals of various ranks measured at Tohoku University (TU). The overall goal is to find equations to calculate FP yields that depend upon the weight percentages [C], [H], and [O] of the feedstock, the a, b, and c of the chemical product (C a H b O c ), the temperature of pyrolysis (T), and the time (t) of application of this temperature. Such a unified model should be useful for many CDF applications and helpful in bringing order to the science of pyrolysis.

Techno-economic analysis of co-fired biomass integrated gasification/combined cycle systems with inclusion of economies of scale

This work focuses on short-term application of biomass integrated gasification/combined cycle (BIG/CC) technology with co-firing of natural gas and biomass derived gas. Co-firing leads to higher efficiency and lower costs of BIG/CC technology. A full technical and economic analysis was carried out by integrating performance modeling from co-fired CC and scale effects over a wide range of capacities (20–300 MW e). The gasification technology is directly air-heated and the feedstock is sugar cane residue. Co-firing alleviates the need for de-rating gas turbines, which would reduce efficiency. It also allows combined cycles to be scaled up beyond the limits imposed by single vessel gasifiers. Mixing of LCV gas and natural gas can greatly improve the cost-effectiveness of power generated by BIG/CC. The cost of electricity (COE) for biomass reaches a minimum with 50% proportion of natural gas in the mixture. For proportions of natural gas higher than 60%, the biomass-based power in a co-firing scheme may become less cost-effective than a BIG/CC. A sensitivity analysis shows that if the energy input consists of 50% biomass, the most sensitive parameters—in decreasing order—are the efficiency, the capital costs of the combined cycle, the gas cleanup equipment and the biomass fuel costs.

Co-firing of natural gas and Biomass gas in biomass integrated gasification/combined cycle systems

This work aims to evaluate the co-firing of gas derived from biomass and natural gas in combined cycles. It is suggested that co-firing can solve some of the initial technological problems associated with the gas turbines of BIG-GT (Biomass Integrated Gasification/Gas Turbine) plants. De-rating is the simplest strategy that allows continuous gas turbine operation with low calorific value fuels, but it also reduces cycle power and efficiency. The proposed biomass gas is derived from sugar-cane residues and has a lower heating value of around to 6 MJ/Nm 3. Modeling results show that if the natural gas content is higher than 35–50% (energy basis) no de-rating will be necessary. At these proportions, the efficiency of electricity generation is not substantially reduced vis-à-vis the reference case. Another important outcome of the modeling is that the peak in power that occurs for natural gas contents slightly higher than 50% in energy basis. Another advantage of co-firing is that it will entail only small hardware modifications to the gas turbines. A comparison is made between the co-firing strategy and the improvements likely to arise from retrofitting gas turbines for LCV fuels.

Reducing Operating Costs in Stoker Boilers With Natural Gas Cofiring

Natural gas cofiring in stoker boilers is now coming of age and maturing as an off-the-shelf tool to improve the economics of stoker boiler firing. Natural gas cofiring is a technology that blends the most desirable characteristics and capabilities of natural gas with more difficult and problematic solid fuels like coal and wood wastes. Natural gas cofiring involves the use of a very small amount of natural gas, typically less than 10%, firing over stoker grates through special burners. This article seeks to review the five most popular economic drivers related to operating cost reductions available through natural gas cofiring.

98/01378 Recent results and plans concerning co-gasification of biomass and coal—an overview: Kurkela, E. Biomass Energy Environ., Proc. Eur. Bioenergy Conf., 9th, 1996, 1, 164–169. Edited by Chartier, P., Elsevier, Oxford, UK

This work focuses on short-term application of biomass integrated gasification/combined cycle (BIG/CC) technology with co-firing of natural gas and biomass derived gas. Co-firing leads to higher efficiency and lower costs of BIG/CC technology. A full technical and economic analysis was carried out by integrating performance modeling from co-fired CC and scale effects over a wide range of capacities (20–300 MWe). The gasification technology is directly air-heated and the feedstock is sugar cane residue. Co-firing alleviates the need for de-rating gas turbines, which would reduce efficiency. It also allows combined cycles to be scaled up beyond the limits imposed by single vessel gasifiers. Mixing of LCV gas and natural gas can greatly improve the cost-effectiveness of power generated by BIG/CC. The cost of electricity (COE) for biomass reaches a minimum with 50% proportion of natural gas in the mixture. For proportions of natural gas higher than 60%, the biomass-based power in a co-firing scheme may become less cost-effective than a BIG/CC. A sensitivity analysis shows that if the energy input consists of 50% biomass, the most sensitive parameters—in decreasing order—are the efficiency, the capital costs of the combined cycle, the gas cleanup equipment and the biomass fuel costs.

98/01379 Removal of tar by secondary air in fluidized-bed gasification of residual biomass: Pan, Y. G. et al. DGMK Tagungsber., 1997, 9703 (Proceedings ICCS '97, volume 2), 1307–1310

This work focuses on short-term application of biomass integrated gasification/combined cycle (BIG/CC) technology with co-firing of natural gas and biomass derived gas. Co-firing leads to higher efficiency and lower costs of BIG/CC technology. A full technical and economic analysis was carried out by integrating performance modeling from co-fired CC and scale effects over a wide range of capacities (20–300 MWe). The gasification technology is directly air-heated and the feedstock is sugar cane residue. Co-firing alleviates the need for de-rating gas turbines, which would reduce efficiency. It also allows combined cycles to be scaled up beyond the limits imposed by single vessel gasifiers. Mixing of LCV gas and natural gas can greatly improve the cost-effectiveness of power generated by BIG/CC. The cost of electricity (COE) for biomass reaches a minimum with 50% proportion of natural gas in the mixture. For proportions of natural gas higher than 60%, the biomass-based power in a co-firing scheme may become less cost-effective than a BIG/CC. A sensitivity analysis shows that if the energy input consists of 50% biomass, the most sensitive parameters—in decreasing order—are the efficiency, the capital costs of the combined cycle, the gas cleanup equipment and the biomass fuel costs.

Developing anthracite coal water slurry fuel

Abstract : Public law has directed the Department of Defense (DOD) to increase the use of coal, particularly anthracite, at steam generating facilities. This study evaluates the feasibility of producing slurry fuel from anthracite coal and examines the combustion characteristics of the anthracite/water fuel slurry. The T-Process, a proprietary process developed by Otisca Industries, Ltd., Syracuse, NY, was used to produce anthracite-based coal water slurries for testing and combustion. Although it is feasible to manufacture anthracite water fuel, the slurries used in this research would not bum well without substantial amounts of natural gas cofiring. Stable combustion with reduced support fuel can probably be achieved by chemically or physically modifying the factors that affect combustion. Additional research to determine the differences between anthracite and bituminous slurries, to increase the residence time for anthracite slurries, and to manufacture slurries with oil rather than water needs to be conducted to help the DOD meet anthracite purchase/consumption targets.

95/00618 The effects of natural gas cofiring on the ignition delay of pulverized coal and coke particles

Using an improved coal-devolatilization model and a simple char-burnout model, we explore possible synergisms in the simultaneous combustion of coal and natural gas. After describing our own work briefly in the context of the conversion of oil boilers to coal burning, we consider the direct use of pulverized coal or of coal-water slurries with gas augmentation, and the two-stage use of pulverized coal or coal-water slurries with gas augmentation. In the first case, we identify advantageous interactions in cofiring which speeds up char-burnout. In the second case, the primary role of the first stage is the “methanogasification” of coal analogous to, and possibly more effective than, the hydrogasification of coal. In both cases, simultaneous coal-gas combustion appears to be synergistic.

The Effects of Natural Gas Cofiring on the Ignition Delay of Pulverized Coal and Coke Particles

ABSTRACT This paper presents the results of a study designed to determine the effects of natural gas cofiring on particle ignition delay for variously sized pulverized coal and coke particles exposed to realistic combustor conditions. A fluidized bed feeder injects small numbers of particles (typically three to five) into a drop tube furnace at temperatures from 1300K to 1500K with heating rates up to 102K/sec. Individual particle ignition times are recorded using an optical sensor at the furnace entrance and a photomultiplter tube at the furnace exit. Ignition delay measurements were performed for various inlet gas velocities, particle volatilities and gas compositions (including variations in oxygen, methane, natural gas, nitrogen and carbon dioxide concentrations). Ignition measurements with particles of different volatile contents, ranging from 7.5% to 36.1%, show that addition of 1% methane by volume reduces the ignition delay of low volatile particles to a level similar to the ignition delays for high volatile coal of the same particle size. Experimental results are compared with ignition delays predicted by using a thermal model of particle behavior coupled with two ignition models—one model based on energy absorption and the other based oh devolatilization. The thermal model includes the effects of gas phase combustion, particle size and swelling, gas and particle velocity and temperature. The energy-ignition model requires an experimentally determined ignition energy for each tested coal. The devolalilization-ignition model predicts ignition delay using a single value for the minimum volatile concentration required for ignition for all tested coals. Both ignition models accurately predict the measured ignition delay for various volatile contents and sizes in cofiring experiments.

Estimating the flexibility of utility resource plans: an application to natural gas cofiring for SO/sub 2/ control

Electric utility planners must cope with large uncertainties concerning fuel prices, environmental laws, power demands, and the cost and availability of new resources. In this situation, flexibility is valuable. A flexible plan is one that enables the utility to quickly and inexpensively change the system's configuration or operation in response to varying market and regulatory conditions. The authors present a decision tree-based method for quantifying the economic value of flexibility. The method is then used to compare the relative flexibility of natural gas cofiring with other strategies to comply with the acid rain control requirements of the 1990 U.S. Clean Air Act Amendments. For the utility studied, they conclude that cofiring gives the system significantly more flexibility than flue gas desulfurization or switching to low sulfur coal. >

Pilot Scale Studies on PCDD/PCDF Formation and Control in Municipal Waste Combustion Systems

Abstract This test program was designed to study Ihe formation and emission of PCDD/PCDF during Refuse Derived Fuel combustion. Tests were conducted in a pilot scale RDF incinerator. Incinerator fly ash hold up for one hour al a temperature of 570°F resulted in an 8 to 20 fold increase in PCDD/PCDF content. Reductions in RDF load were found to decrease PCDD/PCDF emissions. Fluctuations in RDF feed rate produced increases in PCDD/PCDF emissions. Test results suggest the dominani PCDD/PCDF formation mechanism(s) in the incinerator involve organic compounds in entrained fly ash. A combustion strategy for PCDD/PCDF emissions control has been developed. Natural gas co-firing allows RDF load reduction while smoothing temporal and spatial fluctuations in the furnace.

What's flexibility worth? The enticing case of natural gas cofiring

How much cofiring might save—or cost—depends on assumptions about fuel prices, the cost of emissions allowances and other factors. Its value in addressing uncertainty alone might be reason enough to give cofiring serious consideration.