Detailed discussion of the oxy-fuel PF process

PF oxy-fuel power plant process configurations: In oxy-fuel combustion usually between about 60 and 80·10^{−2 m}_m³3, wet of the flue gas is recirculated to the boiler together with the fuel and oxygen from an air separation unit (ASU) [70–76]. Compared to an air fired system, an oxy-fuel power plant has a considerably lower electrical efficiency, which is mainly due to the high energy consumption of the ASU for O₂provision and the CO₂processing unit (CPU). A recent study by Babcock & Wilcox [77] states that with not fully optimized integration of the oxy-fuel power plant system that is expected in retrofit applications, an efficiency penalty of around 10-11 percentage points (on GCV basis) can be expected. With optimal integration, this could be reduced to about 6-7 percentage points (on GCV basis). Other studies focusing on newly built oxy-fuel power plants report energy penalties of about 10 % (on NCV basis) for non-optimized systems and around 7.5 % (on NCV basis) for an optimized system [66].

There are a number of different configurations possible to include gas cleaning units in the oxy-fuel system with three basic design concepts that have received greater attention by industries

GPH(sec.)

GPH(prim.)

ash, (SO_x) coal

primary recycle secondary recycle

O₂

(from ASU)

removalash furnace/

boiler

mill SO_x

removal H₂O removal

CPUto

ash

ash

SO_x H₂O, (SO_x)

SO_x

a) b) c)

1 2

4' 3

4

Figure 2.2:Schematic of an oxy-fuel PF power plant: a), b), and c) show various recycle options; numbers 1, 2, 3, 4, and 4´ show possible locations for dry sorbent injection (DSI).

and researchers [44, 75, 78–81]. Those are included in figure 2.2 that shows the oxy-fuel process schematically with (a) flue gas recirculation after ash removal, (b) flue gas recirculation after SO_x removal, and (c) flue gas recirculation after moisture removal.

Removal of ash before recirculation of flue gases can be considered essential in order to avoid extremely high ash concentrations in the process that would lead to problems, due to erosion and fouling. Therefore, the recirculation after the removal of particulates in a fabric filter or ESP (a) can be considered as the “dirtiest” of the practically relevant flue gas recirculation configurations. Even though filters and ESPs can remove impurities other than ash (e.g. SO₃ [38, 44, 82]), a large part of the sulfur in the flue gas as well as the moisture is recirculated to the boiler in this configuration. This leads to relatively high levels of SO₂and H₂O in the furnace.

Depending on the sulfur retention potential of the ash (i.e. the calcium, magnesium, potassium, and sodium content), high SO_x levels in the oxy-fuel recycle system without SO_x removal can also lead to a more efficient sulfur retention in the ash and therefore, higher sulfur levels in the ash which may have negative implications on ash utilization [41, 42]. In configuration a), DeSO_x and H₂O removal units can be designed much smaller than in the other configurations, since they handle only the flue gas stream exiting the oxy-fuel recycle loop. This stream is considerably smaller than the gas stream within the recycle loop and, due to the absence of airborne N₂, corresponds to only about one fifth of the flue gas flow of a comparable air fired combustor. This is fundamentally different in process configurations b) and c), where SO_x(b) and SO_x and moisture (c) are removed from the recirculated flue gas. The larger gas stream that is to be handled in the respective gas cleaning equipment requires larger unit sizes and therefore, higher investment costs. On the other hand, the separation of SO_x within the recycle leads to much lower SO_xlevels in the boiler which is desirable in respect to boiler fouling and corrosion and can also minimize problems associated with low temperature acid corrosion in

the recycle lines. In addition, it may be beneficial for an oxy-fuel power plant to be capable to keep the legal emission limits during conventional air fired operation periods. This may, for example, be required during start-up and shut-down. Due to the much smaller design of a gas cleaning system in process configuration a) the system may not be capable to keep the legal emission limits (e.g. for SO_x). Configuration b) may provide additional flexibility in that context. If H₂O is removed from the recycled gas, also water concentrations in the boiler are decreased. Water makes up for a large part of the flue gas in an uncleaned recycle configuration (i.e. system a), with reported oxy-fuel H₂O concentrations of up to 28·10^{−2 m}_m³3, wet in pre-dried lignite combustion [36]. A removal of H₂O within the recycle can reduce the water concentration in the boiler by a factor of approx. 4-5. However, the removal of H₂O from the flue gas that is done by cooling and condensation, leads to much lower temperatures of the recirculated gas. Due to flue gas cooling, low temperature heat is generated that is difficult to utilize and hence, often is lost. A similar effect is observed with the application of a wet FGD system that is also related to excessive flue gas cooling and therefore, an energy penalty.

The selection of a recycle configuration for an oxy-fuel power plant depends to a large extent on the sulfur content of the combusted coal [66]. McDonald [80] and Lockwood [66] discussed different process configurations that are suitable for low, medium, and high sulfur coals. They concluded that for low sulfur coals, recirculation after particulates removal (system a), for medium sulfur coals recirculation after a desulfurization step (system b), and for high sulfur coals, recirculation after desulfurization and moisture removal (system c), would be most suitable. For the final design of the Futuregen 2.0⁴ 90 MW (electric, net) oxy-fuel fired power plant that was planned to use a medium sulfur coal blend, configuration b) with a circulating dry scrubber (CDS) for desulfurization was foreseen [77]. A partial desulfurization by DSI may also allow the application of higher sulfur fuels in configuration a).

Stakeholders from research and industry generally agree that, in all relevant oxy-fuel recycle configurations, the recirculated flue gas that is fed to the mills for coal drying and conveying (i.e. the primary recycle gas) needs to be desulfurized, dried, and reheated [73, 74, 80, 81, 83].

Drying and reheating of the recirculated gas is necessary, so that the gas is capable to dry the coal. The desulfurization of the gas should be done in order to avoid SO₃ or SO₂ induced low temperature corrosion in the recycle lines and mills that would occur if temperatures drop below the sulfuric acid or water dew point, respectively [80].

Since recycled NO_xis reburned efficiently when passing the flame zone [17, 65], the recirculation of NO_x poses no critical operational problems to the oxy-fuel combustion process and hence, NO_x reduction units (i.e. SNCR, SCR) are not strictly needed in an oxy-fuel recycle loop.

However, in industrial practice, an oxy-fuel power plant would possibly be operating with conventional air firing during certain periods, such as start-up and shut-down. Depending on

4The FutureGen 2.0 oxy-fuel project has been stopped just before starting construction in 2015, due to a lack in public co-funding.

the local emission regulations, it may be necessary for an oxy-fuel power plant to have flue gas cleaning equipment, such as SCR, SNCR, and wet FGD, available in order to keep emission limits during air fired operation. Different regulatory situations in various countries are to some degree reflected in the actual or planned designs of oxy-fuel pilot and demonstration plants. For example, in Australian (CS Energy’s ‘Callide’ project [81]) or US oxy-fuel projects (FutureGen 2.0 designs [77, 80]) no SCR system was included, while in European projects, SCR systems were foreseen as an option (e.g. Vattenfall’s oxy-fuel pilot plant “Schwarze Pumpe”

[84]; Design of Vattenfall’s oxy-fuel demonstration project [85]) or plants have been built with a fully operational SCR system, such as CIUDEN’s 20 MW (thermal) oxy-fuel system [86].

An important part of the design of an oxy-fuel recycle system is the addition of oxygen to the process. Even though, explosion hazards in 21/79·10^{−2 m}_m³3, dry mixtures of O₂ and N₂ (i.e. air) and O₂and CO₂ (i.e. oxy-fuel) are comparable, the addition of O₂to the primary gas poses a general risk of increased O₂concentrations in this gas stream in events, such as mill start-up and shut-down, and failures of equipment, such as the recycle gas fan [87]. Therefore, in practical systems no O₂is added to the primary gas, supplied to the mills. It should however be noted that the primary recycle gas does contain few percent of O₂ that originate from the O₂excess of combustion. Instead, O₂can either be added to the secondary recycle gas or it can be directly injected to the furnace via pure O₂annuli or lances of the burner. Moreover, a hybrid operation with partial O₂premixing to the secondary recycle and additional direct O₂ injection via the burner is possible [2, 88–90]. The direct O₂injection and the hybrid injection showed positive effects on the combustion behavior in pilot tests by Vattenfall [88].

Factors affecting the purity of the generated CO2: The product of the oxy-fuel combus-tion process is a CO₂rich flue gas stream that is subsequently cleaned and liquefied for transport and storage. To reduce the energy requirement for CO₂compression and liquefaction, high CO₂ purities of the oxy-fuel flue gas are desirable [91]. This purity depends on the extent of air ingress, the oxygen excess in combustion, and the purity of the used oxygen. Depending on these factors, the recirculated flue gas after drying may contain around 5-30 % of the ballast gases O₂, N₂, and Ar [69, 85, 88, 89, 92–94]. In addition, impurities, such as CO, NO_x, SO_x, and mercury that origin from the fuel or its combustion are present in the oxy-fuel flue gas, but their concentrations are usually much lower. Nonetheless, these components are problematic, due to their corrosivity, so that they need to be removed.

One measure to obtain high CO₂purities in the oxy-fuel combustion process is the application of highly pure O₂ (i.e. 99.5·10^{−2 m}_m³₃, dry). However, in future commercial oxy-fuel projects an economic optimum for oxygen purity from the ASU is around 95·10^{−2 m}_m³3, dry [85, 88].

The approx. 5·10^{−2 m}_m³3,dry of N₂ and Ar that are supplied with the O₂ feed will lead to an increase on the ballast gas in the flue gas in a similar order of magnitude. The ingress of air to an oxy-fuel combustion process is another source of ballast gas that can lead to a considerable

contamination of the CO₂ purity and therefore, an increased energy requirement for CO₂ purification [91]. Since N₂from air leakage accumulates in the recycle loop, even small leaks with only little air ingress can lead to a considerable flue gas contamination [88, 92, 95].

Another source of dilution of the CO₂purity is O₂ that originates from the operation of the combustion process with excess oxygen. To achieve a high burnout and low CO concentrations in the flue gas, O₂needs to be supplied in excess to balance imperfect mixing in the furnace.

This implies that CO₂ contamination by few percentage points of excess oxygen cannot be avoided in oxy-fuel combustion processes. In Vattenfall’s oxy-fuel pilot plant “Schwarze Pumpe” stoichiometric ratios of combustion between approx. 1.1 and 1.2 were necessary to avoid excessive CO generation [89]. A difference between air and oxy-fuel combustion is that different oxidant O₂concentrations imply different excess O₂ concentrations to reach the same combustion stoichiometry (see also section 4.2.1.4). Higher oxidant O₂ concentrations that are equivalent to low flue gas recirculation ratios are desirable to reduce gas streams in the process and therefore, plant dimensions and auxiliary fan power. On the other hand, at high oxidant O₂concentrations, a complete combustion of the fuel without generation of high CO concentrations requires considerably higher excess O₂ concentration levels [88] and therefore, leads to increased contamination of the CO₂rich flue gas by O₂. This problem can be counterbalanced by an enhancement of the oxy-fuel firing system so that it can be reliably operated at a stoichiometry lower than the ones applied in conventional air fired systems.

For example, after optimization, Vattenfall’s oxy-fuel pilot plant “Schwarze Pumpe” could be successfully operated with 2.5·10^{−2 m}_m³3, wet excess O₂ at an oxidant O₂ concentration of 31·10^{−2 m}_m³3, wet (i.e.n_O2,loc ≈1.1) [88].

The flue gas that leaves the oxy-fuel recycle loop is fed to a CO₂processing unit. In this system, it is compressed and impurities, such as H₂O, NO_x, SO_x, and mercury, are removed according to the requirements of the CPU system and the downstream handling (i.e. pipeline transport, geological storage, or CO₂utilization). A removal of part of the impurities before compression (i.e. in the low pressure oxy-fuel system) may be mandatory or economic (e.g. the bulk of SO_x and H₂O). The cleaned and compressed CO₂rich stream is finally liquefied in the CPU. Ballast gases that cannot be liquefied in the CO₂liquefaction system need to be vented.