Oxyfuel indirect heating steam cycle

In these systems, the oxy-fuel combustion chamber provides heat to a separate fluid by heat transfer through a surface. It can be used for either process heating, or in a boiler with a steam cycle for power generation. The indirect system can be used with any hydrocarbon or carbon-containing fuel.

The application of oxy-fuel indirect heating for CO2 capture in process heating and power generation has been examined in both pilot-scale trials evaluating the combustion of carbonaceous fuels in oxygen and CO2-rich recycled flue gas mixtures and engineering assessments of plant conversions as described below.

3.4.2.1 Oxy-fuel combustion trials

Work to demonstrate the application of oxy-fuel recycle combustion in process heating and for steam generation for use in steam power cycles have been mostly undertaken in pilot scale tests that have looked at the combustion, heat transfer and pollutant-forming behaviour of natural gas and coal.

One study carried out (Babcock Energy Ltd. et al., 1995) included an oxy-fuel test with flue gas recycle using a 160kW, pulverized coal, low NO burner. The system included a heat-transfer test section to simulate fouling conditions. Test conditions included variation in recycle flow and excess O2 levels. Measurements included all gas compositions, ash analysis and tube fouling after a 5-week test run. The work also included a case study on oxy-fuel operation of a 660 MW power boiler with CO2 capture, compression and purification. The main test results were that NOx levels reduced with increase in recycle rate, while SO2 and carbon in ash levels were insensitive to the recycle rate. Fouling in the convective test section was greater with oxy-fuel firing than with air. High-slagging UK coal had worse slagging when using oxy-fuel firing, the higher excess O2 level lowered carbon in ash and CO concentration.

For the combustion of pulverized coal, other pilot-scale tests by Croiset and Thambimuthu (2000) have reported that the flame temperature and heat capacity of gases to match fuel burning in air occurs when the feed gas used in oxy-fuel combustion has a composition of approximately 35% by volume O2 and 65% by volume of dry recycled CO2 (c.f. 21% by volume O2 and the rest nitrogen in air). In practice, the presence of inerts such as ash and inorganic components in the coal, the specific fuel composition and moisture in the recycled gas stream and the coal feed will result in minor adjustments to this feed mixture composition to keep the flame temperature at a value similar to fuel combustion in air.

At conditions that match O2/CO2 recycle combustion to fuel burning in air, coal burning is reported to be complete (Croiset and Thambimuthu, 2000), with operation of the process at excess O2 levels in the flue gas as low as 1-3% by volume O2, producing a flue gas stream of 95-98% by volume dry CO2 (the rest being excess O2, NOx, SOx and argon) when a very high purity O2 stream is used in the combustion process with zero leakage of ambient air into the system. No differences were detected in the fly ash formation behaviour in the combustor or SO2 emissions compared to conventional air firing conditions. For NO on the other hand, emissions were lower due to zero x thermal NOx formation from the absence of nitrogen in the feed gas - with the partial recycling of NO also reducing the formation and net emissions originating from the fuel bound nitrogen. Other studies have demonstrated that the level of NO reduction is as high as 75% compared to coal burning in air (Chatel-Pelage et al., 2003). Similar data for natural gas burning in O2/CO2 recycle mixtures report zero thermal NOx emissions in the absence of air leakage into the boiler, with trace amounts produced as thermal NOx when residual nitrogen is present in the natural gas feed (Tan et al., 2002).

The above and other findings show that with the application of oxy-fuel combustion in modified utility boilers, the nitrogen-free combustion process would benefit from higher heat transfer rates (McDonald and Palkes, 1999), and if also constructed with higher temperature tolerant materials, are able to operate at higher oxygen concentration and lower flue gas recycle flows - both of which will considerably reduce overall volume flows and size of the boiler.

It should be noted that even when deploying a 2/3 flue gas recycle gas ratio to maintain a 35% by volume O2 feed to a pulverized coal fired boiler, hot recycling of the flue gas prior to CO2 purification and compression also reduces the size of all unit operations in the stream leaving the boiler to 1/5 that of similar equipment deployed in conventional air blown combustion systems (Chatel-Pelage et al., 2003). Use of a low temperature gas purification step prior to CO2 compression (see Section 3.4.2.2) will also eliminate the need to deploy conventional selective catalytic reduction for NOx removal and flue gas desulphurization to purify the gas, a practice typically adopted in conventional air-blown combustion processes (see Figure 3.3). The overall reduction in flow volumes, equipment scale and simplification of gas purification steps will thus have the benefit of reducing both capital and operating costs of equipment deployed for combustion, heat transfer and final gas purification in process and power plant applications (Marin et al., 2003).

As noted above for pulverized coal, oil, natural gas and biomass combustion, fluidized beds could also be fired with O2 instead of air to supply heat for the steam cycle. The intense solid mixing in a fluidized bed combustion system can provide very good temperature control even in highly exothermic conditions, thereby minimizing the need for flue gas recycling. In principle, a variety of commercial designs for fluidized combustion boilers exist that could be retrofitted for oxygen firing. A circulating fluidized bed combustor with O2 firing was proposed by Shimizu et al. (1999) to generate the heat required for the calcination of CaCO3 (see also Section 3.3.3.4). More recently, plans for pilot testing of an oxy-fired circulating fluidized bed boiler have been published by Nsakala et al. (2003).

3.4.2.2 Assessments of plants converted to oxy-fuel combustion

We now discuss performance data from a recent comprehensive design study for an application of oxy-fuel combustion in a new build pulverized coal fired power boiler using a supercritical steam cycle (see Figure 3.8; Dillon et al., 2005). The overall thermal efficiency on a lower heating value basis is reduced from 44.2% to 35.4%. The net power output is reduced from 677 MW to 532 MW .

Important features of the system include:

• Burner design and gas recycle flow rate have been selected to achieve the same temperatures as in air combustion (compatible temperatures with existing materials in the boiler).

• The CO2-rich flue gas from the boiler is divided into three gas streams: one to be recycled back to the combustor, one to be used as transport and drying gas of the coal feed, and the third as product gas. The first recycle and the product stream are cooled by direct water scrubbing to remove residual particulates, water vapour and soluble acid gases such as SO3 and HCl. Oxygen and entrained coal dust together with the second recycle stream flow to the burners.

• The air leakage into the boiler is sufficient to give a high enough inerts level to require a low temperature inert gas

Figure 3.8 Schematic of an oxy-fuel, pulverized coal fired power plant.

removal unit to be installed, even if pure O2 were used as the oxidant in the boiler. The cryogenic oxygen plant will, in this case, produce 95% O2 purity to minimize power consumption and capital cost.

• The low temperature (-55°C) CO2 purification plant (Wilkinson et al., 2003b) integrated with the CO2 compressor will not only remove excess O2, N2, argon but can also remove all NOx and SO2 from the CO2 stream, if high purity CO2 is required for storage. Significantly, removal of these components before final CO2 compression eliminates the need to otherwise incorporate upstream NOx and SOx removal equipment in the net flue gas stream leaving the boiler. Elimination of N2 from the flue gas results in higher SO concentrations in the boiler and reduced NO levels.

Suitable corrosion resistant materials of construction must be chosen.

• The overall heat transfer is improved in oxy-fuel firing because of the higher emissivity of the CO2/H2O gas mixture in the boiler compared to nitrogen and the improved heat transfer in the convection section. These improvements, together with the recycle of hot flue gas, increase the boiler efficiency and steam generation by about 5%.

• The overall thermal efficiency is improved by running the O2 plant air compressor and the first and final stages of the CO2 compressor without cooling, and recovering the compression heat for boiler feed water heating prior to de-aeration.

Engineering studies have also been reported by Simbeck and

McDonald (2001b) and by McDonald and Palkes (1999).

This work has confirmed that the concept of retrofitting oxy-

fuel combustion with CO2 capture to existing coal-fired power stations does not have any technical barriers and can make use of existing technology systems.

It has been reported (Wilkinson et al., 2003b) that the application of oxy-fuel technology for the retrofit of power plant boilers and a range of refinery heaters in a refinery complex (Grangemouth refinery in Scotland) is technically feasible at a competitive cost compared to other types of CO2 capture technologies. In this case, the existing boiler is adapted to allow combustion of refinery gas and fuel oil with highly enriched oxygen and with partial flue gas recycling for temperature control. Oxy-fuel boiler conversions only needed minor burner modifications, a new O2 injection system and controls, and a new flue gas recycle line with a separate blower. These are cheap and relatively simple modifications and result in an increase in boiler/heater thermal efficiency due to the recycle of hot gas. Modifications to a coal-fired boiler are more complex. In this study, it was found to be more economic to design the air separation units for only 95% O2 purity instead of 99.5% to comply with practical levels of air leakage into boilers and to separate the associated argon and nitrogen in the CO2 inert gas removal system to produce a purity of CO2 suitable for geological storage. After conversion of the boiler, the CO2 concentration in the flue gas increases from 17 to 60% while the water content increases from 10 to 30%. Impurities (SOx, NOx) and gases (excess O2, N2, argon) representing about 10% of the stream are separated from CO2 at low temperature (-55°C). After cooling, compression and drying of the separated or non-recycled flue gas, the product for storage comprises 96% CO2 contaminated with 2% N2, 1% argon and less than 1% O2 and SO2. Production of ultra-pure CO2 for storage would also be possible if distillation steps are added to the separation process.

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