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Optimization of CO2 compression and purification units (CO2CPU) for CCS power plants
Fuel 101 (2012) 254–263
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Optimization of CO2 compression and purification units (CO2CPU) for CCS power plants Sebastian Posch ⇑, Markus Haider Institute of Energy Systems and Thermodynamics, Vienna University of Technology, Getreidemarkt 9/E302, A-1060 Vienna, Austria
a r t i c l e
i n f o
Article history: Received 28 September 2010 Received in revised form 23 July 2011 Accepted 26 July 2011 Available online 9 August 2011 Keywords: CCS, carbon capture and storage CO2 compression CO2 quality Oxy-fuel Purification
a b s t r a c t Oxy-fuel power plants are among the currently known major carbon capture and storage (CCS) technologies those which produce the lowest carbon dioxide (CO2) purity CO2-stream. As a consequence, the oxy-fuel technology has the highest requirement towards CO2 purification. In the current paper two different purification processes are modeled in Aspen Plus™ based on a Peng–Robinson property method with kij mixing coefficients. Both separation processes are based on phase separation technique. The first one is equipped with two flash columns and the second one includes a distillation column. Both plants require a dehydration plant for water removal. For each process the impact of main design parameters on performance features such as specific power requirement, specific cooling duty, separation efficiency and CO2 purity are analyzed, including variations in flue gas composition, plant load and kij mixing parameters. The results were compared to a conventional 5-stage CO2 compressor. Ó 2011 Elsevier Ltd. All rights reserved.
1. Introduction Nowadays, many researchers agree that anthropogenic greenhouse gases (GHG) provoke a change in climate. Since 1750 the global atmospheric concentrations of carbon dioxide, methane and nitrous oxide increased vehemently due to human activities. The global increase in CO2 is supposed to be mainly caused by fossil fuel use and land use [1]. According to the outlook of the International Energy Agency (IEA) [2] fossil fuels still are going to play a major role in the next decades to satisfy the world energy demand. Among the fossil fuels coal shows the highest reserves, however coal also has the highest specific carbon dioxide emissions within the fossil fuels. In order to combine the satisfaction in world energy demand and the reduction of greenhouse gases different strategies have to be followed over the next decades simultaneously [2]. These are Increase in energy efficiency. Renewable energy. Carbon capture and storage (CCS). The idea behind carbon capture and storage is to separate the carbon dioxide from flue gases. The captured CO2 is further
⇑ Corresponding author. Tel.: +43 1 58801 30211, mobile: +43 650 5711989; fax: +43 1 58801 30299. E-mail address: [email protected] (S. Posch). 0016-2361/$ - see front matter Ó 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.fuel.2011.07.039
compressed and transported to different storage sites, which are saline aquifers or depleted oil and gas fields. Furthermore the separated and compressed carbon dioxide can increase oil or gas field extraction by enhanced oil or gas recovery (EOR/EGR). In all storage options, the compressed stream of CO2 has to fulfill particular purity requirements. They are most stringent in case of EOR/EGR. Carbon capture and storage can be classified into three different technologies. Post combustion capture. Pre combustion capture. Oxy-fuel technology. A detailed description of each technology can be found in many literature sources, i.e. [3]. Even if the separation approach is completely different at all three technologies, they have a CO2 compressor station in common to make an economic transport of CO2 possible. Within this paper the compression and purification of an oxy-fuel derived flue gas stream was considered. The primary goal was to generate the characteristic diagrams of two different CO2-compression and purification units (CO2CPU) with respect to specific energy and cooling water consumption, CO2-purity and separation efficiency. These values were compared with a conventional 5-stage compressor for CO2. In addition the influence of different power plant loads and fuels was analyzed. Finally also the influence of different kij mixing parameters from Peng–Robinson equation of state was considered.
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255
Nomenclature
a ac a b kij _ CO2 sep m _ CO2 0 m n
gsep p patt prep pc R
constant, describing the attractive interaction (J m3 mol2) substance specific constant in the attractive interaction (J m3 mol2) temperature dependent function to adjust the attractive interaction (–) constant, describing the repulsive interaction (m3 mol1) mixing parameter (–) mass flow of the purified CO2 (kg s1) mass flow of the raw flue gas stream (kg s1) amount of species in the mixture (–) mass related separation efficiency (–) actual pressure (Pa) attraction term of the actual pressure (Pa) repulsion term of the actual pressure (Pa) critical pressure (Pa) universal gas constant (8.314 J mol1 K1)
2. Previous work Since oxy-fuel combustion for power plant has not reached full scale, the main focus right now lies on research and development. Regarding to compression and purification units, several papers and patents were published in recent times. Darde et al. [4] presented in their work some basic considerations on CO2CPU. Pipitone and Bolland [5], Ritter et al. [6] as well as White et al. [7] presented and compared carbon dioxide compression and purification units for oxy-fuel combustion in their work. Furthermore Eldevik et al. [8] and de Visser et al. [9] presented first considerations and guidelines regarding CO2 product quality. Santos [10] as well as Eggers and Köpke [11] presented appropriate values for kij mixing parameters for Peng–Robinson equation of state with respect to carbon dioxide. This work mainly focuses on the separation plants which were suggested in Ritter et al. [6] and White et al. [12]. Small modifications were done to achieve high reliability of each CO2CPU. 3. Purity requirements Flue gas composition varies with the fuel used and carbon dioxide separation technology. In case of oxy-fuel combustion of coal the derived flue gas consists mainly of carbon dioxide (CO2) and water (H2O). Due to air leakage and excess of oxygen during the combustion also nitrogen (N2) and oxygen (O2) are present in oxy-fuel derived flue gas. As long as coal is fired in the boiler the flue gas will also contain sulfur oxides (SOx), nitrogen oxides (NOx), traces of mercury and other organic or inorganic components [1]. In order to establish the whole chain of CCS, the separated carbon dioxide has to be compressed, transported and stored. Due to environmental regulations, technical, economical and/or safety reasons [9] published some basic guidelines concerning impurities in a carbon dioxide stream which is provided for storage or EOR and EGR. These guidelines are the result of basic considerations on the following points [9]: Safety and toxicity of substances present in the CO2 stream. Avoidance of free water formation. Avoidance of hydrate formation. Avoidance of corrosion. Reduction of the CO2 volume.
T Tc Tr Vm y
x
actual temperature (K) critical temperature (K) reduced temperature (–) molar volume (m3 mol1) mole fraction (–) acentric factor (–)
Subscripts i component i in the mixture (–) j component j in the mixture (–) ii value for pure fluid i (–) ij interaction between component i and component j in the mixture (–) jj value for pure fluid j (–) 0 at the inlet of the CO2CPU (–) 1 at position 1 in the CO2CPU (–) 2 at position 2 in the CO2CPU (–) 3 at position 3 in the CO2CPU (–)
The specifications can be seen in Table 1. Additionally to the Dynamis guideline two other quality specifications are included in Table 1 for EOR projects in the United States of America [13,9]. In order to minimize the specific compression work and cooling duty per separated carbon dioxide the CO2 content shall reach at least 95%. Since the presence of free water enhances corrosion and hydrate formation the maximum H2O content shall not exceed 500 ppm, in order to avoid free water formation [9]. The entire content of non condensable gases such as argon (Ar), hydrogen (H2) and nitrogen (N2) is set smaller than 5%. The non condensable gas H2 shall be minimized in the CO2 stream, since it requires a very high specific compression work and represents a considerable sink of energy. With respect to toxicity the contents of nitric oxide (NOx) and sulfur oxide (SOx) shall be kept under the threshold of 100 ppm, in order to avoid health effects in a case of a sudden leakage [9]. Moreover, the tolerable oxygen (O2) content varies, if the CO2 is stored in saline aquifers or if it is used for EOR and EGR. In case of enhanced oil or gas recovery the oxygen content shall not reach the limit of 100 ppm. Pipitone and Bolland [5] state that higher concentrations in oxygen may cause severe problems: Overheating at the injection point. Oxidation in the reservoir with higher oil viscosity and increased extraction cost. Increased biological growth with unknown effects on oil production. 4. Equation of state (EOS) For all simulations in the present publication the Peng–Robinson equation of state [14] was chosen as the most appropriate equation for the calculation of fluid properties in the purification process. The Peng–Robinson equation is a cubic equation of state based on the theorem of corresponding states, which basically says that the compressibility factor of a pure fluid can be expressed by its critical pressure and temperature as well as its acentric factor. Derived from the van-der-Waals equation of state, the Peng–Robinson equation of state consists of a repulsion term prep and an attraction term patt. Both terms are describing the actual pressure in the system:
P ¼ prep þ patt
ð1Þ
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Table 1 Different specifications of CO2-composition after purification. US pipeline quality specifications [13]
Weyburn EOR project [1]
Dynamis [9]
CO2 Ar CxHy
>95% – <5%
>96% – <0.7%
CO H2O H2S N2 NOx O2
– 0.4805 g/Nm3 10 – 200 ppm <4% – <10 ppm
<1000 ppm <20 ppm <9000 ppmv <300 ppm – <50 ppm
SOx Temperature
– <50 °C
– <50 °C
>95.5% <4% <4% (saline aquifers) <2%vol (EOR) <2000 ppm <500 ppm <200 ppm <4% <100 ppm <4% (saline aquifers) <100–1000 ppm (EOR) <100 ppm –
For the Peng–Robinson equation the parameters a(T) and b are introduced to get an adequate description of the vapor–liquid properties of the fluid. The main difference to the van-der-Waals equation of state is the temperature dependency of the attraction term a(T). The Peng–Robinson equation of state results to
P¼
RT aðTÞ V m b V 2m þ 2V m b b2
ð2Þ
where a(T) is defined by:
aðTÞ ¼ ac aðTÞ
ð3Þ
The constants ac and b in Eqs. (2) and (3) are related to the critical point of the substance.
ac ¼ 0:4572
R2 T 2c
pc RT c b ¼ 0:07780 pc
ð4Þ ð5Þ
The temperature dependency of the attraction term is again described by an empirical formula [14].
sffiffiffiffiffi!!2 T 2 aðTÞ ¼ 1 þ ð0:37464 þ 1:54226 x 0:26992 x Þ 1 Tc ð6Þ In Eq. (6) x designates the acentric factor, introduced by Pitzer et al. [15], which represents the vapor pressure curve and is specific to each substance and calculated by:
x ¼ 1:000 log10 ðp0r ÞT r ¼0:7
ð7Þ
In Eq. (7) ðp0r ÞT r ¼0:7 designates the reduced saturation vapor pressure at the reduced temperature Tr = 0.7. For pure carbon dioxide the critical values are taken as follows: pc = 7.375E6 Pa, Tc = 304.184 K and x = 0.239. 4.1. Homogeneous, multi component mixtures The Peng–Robinson equation of state (2) allows the calculation of the liquid and the gas phase properties for a pure fluid. To describe vapor and liquid properties of a homogenous, multi component mixture the Peng–Robinson equation of state has to be extended by mixing rules. A number of mixing rules can be found in the literature; however, most of them do not base on a strict theoretical approach but results empirically from multi component measurements. The simplest empirical approach for a cubic equation of state is described in this section. To achieve good predictions of the liquid and gaseous properties, the attraction and the repulsion term for the Peng–Robinson equation (2) have to be adjusted. The repulsive term for the
mixture follows from the arithmetic average of the repulsive term for each species multiplied by its mole fraction.
b¼
n X
yi bi
ð8Þ
i¼1
In Eq. (8) bi for each species i is calculated by Eq. (5). The attraction term for multi component mixtures has a quadratic dependency of the mole fraction and is calculated by:
a¼
n X n X i¼1
yi yj
pffiffiffiffiffiffiffiffiffiffi aii ajj ð1 kij Þ
ð9Þ
j¼1
For better results of vapor–liquid properties equation (9) is extend by the binary mixing parameter kij. These mixing parameters have typically very small values; however, they have a remarkable influence on the results of the calculation. It is further possible to introduce a temperature dependency of the binary mixing parameter kij described by: ð2Þ
ð1Þ
ð2Þ
kij ðTÞ ¼ kij þ kij T þ
kij
ð10Þ
T
For all values of kij the following relationship (11) is fulfilled.
kij ¼ kji
ð11Þ
Eqs. (1)–(11) are implemented in the AspenPlus™ process simulation software. The critical point properties for each species as well as the acentric factor are provided by the AspenProperties™ databank. kij mixing parameters are also provided by AspenProperties™ where possible, however they can be manipulated by the user if more adequate values are present. 5. Purification process Within this paper two different CO2 compression and purification units for an oxy-fuel derived flue gas stream were modeled in AspenPlus™ and compared to a conventional compression unit without purification of the CO2 stream. The Peng–Robinson model was chosen as property method for fugacity and thermal state equations. Mixing parameters kij were taken from [11] and are listed in Table 2. Both CO2CPU’s operate on the basis of phase Table 2 kij mixing parameters for Peng–Robinson equation of state [11]. Species 1
Species 2
kij-Value
CO2 CO2 CO2 CO2
Ar O2 N2 SO2
0.1230 0.1116 0.0115 0.0559
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separation techniques, where type 1 is working with flash separation and type 2 has a distillation column, which is equipped with six equilibrium stages. In every case the oxy-fuel derived flue gas is saturated with water before entering the compression and purification unit. The intercooling duty at each type of compression and purification unit as well as for the conventional CO2 compressor has to be delivered by the cooling water of the power plant and by additional cooling facilities. Polytropic efficiency of each compressor stage was assumed with 0.8. All three types of CO2CPU deliver a compressed CO2 stream at final pressure p3. The dehydration plant is simulated as a conventional separator without any energy input, only the compression duty for the additional water in the flue gas to pressure p1 is considered in the simulation. For a save and undisturbed operation of the compression and purification unit it is absolutely necessary to avoid ice formation in the CO2CPU. Since no liquefaction is possible at pressures below the triple point, temperatures below 56.55 °C have to be avoided in order to prohibit the formation of solid carbon dioxide in the CO2CPU.
257
CO2 rich liquid stream. Both streams, the liquid and the gaseous one, are connected to the second multi stream heat exchanger again to act as the cooling agent. The CO2 poor stream passes the first multi stream heat exchanger before it leaves the CO2 compression unit. Since this stream is still at elevated pressure and at low temperature it can be used as a cooling agent somewhere else in the oxy-fuel process (i.e. in the air separation unit). After reheating this stream it can be further expanded in a gas turbine to deliver electric power before it leaves the plant at atmospheric pressure. This benefit was not considered in this work. The CO2 rich stream passes an adiabatic throttle (3-TH1), expands and enters the multi stream heat exchanger 2-HX1 again. Both liquid streams from the two flash columns act again as the cooling agent for multi stream heat exchanger 1-HX1. The CO2-stream coming from the second flash column is recompressed and connected with the former liquid stream from the first flash column 1-FL1. The resulting high concentrated CO2 stream enters the final two stage compression train with intercooling. The CO2 stream is compressed to 80 bar and cooled down to 25 °C where it is in supercritical dense state and can be pumped up to final pressure p3.
5.1. Type 1: Double flash separation – internal cooling 5.2. Type 2: Separation by distillation – external and internal cooling Compression and purification unit 1 is an auto-refrigerated system and is shown in Fig. 1. The flue gas stream enters the precompression train and is compressed to p1. In order to reduce work requirement, the precompression is done in three stages with intercooling down to 25 °C flue gas temperature after each intercooler. Every intercooler is equipped with a condensate trap to avoid the inlet of water droplets in the next compressor stage. After precompression the flue gas stream passes the dehydration plant, where the water content is reduced to 20 ppm in order to fulfill the Dynamis recommendation. Further the flue gas is partly condensed at temperature T2 in the first multi stream heat exchanger 1-HX1 (stream 3 in Fig. 1). The liquid–gas mixture then reaches the first flash column (1-FL1). The gaseous part, dilute in carbon dioxide, is further cooled to 54.5 °C in the second multi stream heat exchanger (2-HX1), where again the gaseous stream condenses partly into a 2-phase mixture. In a second flash column (2-FL1) the stream is again separated in a CO2 poor vapor and a
In the second compression and purification unit the two flash columns from type 1 are replaced by a distillation column in order to increase the purity of the compressed CO2 stream (Fig. 2). Again the saturated raw gas from the oxy-fuel power plant is precompressed to p1, passes the dehydration plant and the multi stream heat exchanger 1-HX1 where it is cooled down to temperature T2 and enters the distillation column 2-D1. The vaporous product of 2-D1 is partly condensed (2-HX1) to a vapor fraction of 0.75, where the cooling duty is delivered by an external ammonia cooling cycle. The two phase stream then is separated. The liquid part runs back in 2-D1. The vaporous part reenters 1-HX1 where it is partly condensed at 54.5 °C. The vapor–liquid mixture is separated in flash column 3-FL1. The gaseous stream passes an adiabatic throttle, where the stream is cooled down to 55.5 °C and reenters the multi stream heat exchanger. Since the stream still comprises cooling capacity it is again expanded in a second adiabatic throttle and
Fig. 1. Double flash compression and purification unit – internal cooling.
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Fig. 2. Compression and purification unit with distillation column – external and internal cooling.
reenters the multi stream heat exchanger once again. After passing the heat exchanger the waste stream acts as the cooling agent for the recompression of the liquid branch from flash column 3-FL1. Analogous to type 1 compression unit this waste stream comprises cooling potential, which can be taken into account in the air separation unit. Again this benefit was not considered in this work. The liquid stream from 3-FL1 also serves as a cooling agent in 1-HX1 until it is reconnected with the original flue gas stream. The liquid product of the distillation column is partly evaporated by the external ammonia cycle to a vapor fraction of 0.45, where the resulting vaporous part reenters the distillation column. The residual liquid product passes an adiabatic throttle, enters the multi stream heat exchanger and is then compressed to 68 bar and finally pumped to the final pressure p3. 5.3. Type 3: Standard five stage compressor Both types of the mentioned CO2CPU’s are compared to a conventional five stage compression train for carbon dioxide as
depicted in Fig. 3. This standard multistage compressor has again an intercooler behind each stage. The first three stages are equipped with a condensate trap after the intercooler in order to avoid erosion in the following stages due to water droplets. After the third compressor stage the precompressed flue gas passes through the dehydration plant. From there the dehydrated carbon dioxide stream enters the final compression stages, where it is compressed to pressure p3. 6. Characteristics of the CO2CPU’s First point of interest in this work was to generate the characteristics of each CO2 compression and purification unit and to minimize for each process separately the required power and amount of cooling water. The discharge pressure p1 of the precompression train was varied at both types of CO2CPU. For both types also the outlet temperature of the first multistream heat exchanger T2 was varied. In a first calculation the discharge pressure p1 was varied between 13 and 32 bar. In addition the condensation
Fig. 3. Conventional 5-stage compressor with intercooling.
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temperature T2 lies between 20 and 30 °C for CO2CPU type 1 and between 35 and 42.5 °C for CO2CPU type 2. To determine the characteristics of each type of CO2CPU a saturated oxy-fuel derived flue gas enters the precompression train. The composition is specified as ‘‘coal-max’’ in Table 3. The flue gas composition was calculated in a detailed retrofit study for an existing coal power plant. Older coal fired plants operate at higher excess oxygen than modern state of the art technology. In addition, parasitic air intrusion in retrofit situations will be higher than in tailor made oxy-fuel steam generators. As a result, the O2-purity of the oxy-fuel product stream is lower and the requirements for CO2CPU are higher in retrofit than in Greenfield oxy-fuel CCS. 6.1. Specific compression power First task of this work was to determine the trend of specific compression power for each CO2CPU. The results for all types are depicted in Fig. 4. For double flash compression unit type 1 the specific compression power is a strong nonlinear function of the precompression pressure p1. In Fig. 4 precompression pressure starts at 13 bar and ends up at 32 bar. At lower pressures the required cooling demand cannot be provided in the heat exchangers due to p, T-behavior of CO2 where at higher pressures no condensation will result at pressures p = 80 bar at the end of the compression unit. The set of T2-isotherms in Fig. 4 shows two local minima and one local maximum in specific work duty by varying pressure p1 for CO2CPU type 1. The local minimum at lower pressures of p1 results from two contrariwise effects in the compression train. With increasing pressure p1 a larger part of the gaseous CO2stream condensates in the multi stream heat exchanger 2-HX1 which leads to a decrease in specific compression duty. On the other hand an increase in mass flow leads to higher compression work in the second compression train, since the pressure ratio over the adiabatic throttle increases with higher pressures p1. The local maximum on the T2-isotherms in Fig. 4 results from the two installed flash columns in CO2CPU type 1. Since the condensation temperature is a function of pressure p1, partial condensation starts in the first multi stream heat exchanger at elevated pressures p1. Due to absence of recompression in the liquid branch of the first flash column this stream directly enters the second compression train after passing the first heat exchanger. Therefore the specific compression duty starts to decrease again at elevated pressures p1. At lower condensation temperatures T2 a second local minimum can be observed in Fig. 4. This minimum again is caused by the same reason than the first minimum due to the two contrary effects as explained before. To keep the specific compression duty as low as possible, the condensation temperature T2 in the first heat exchanger has to be kept as low as possible too. The limiting case arises from the fact, that the condensation temperature in the second heat exchanger and therefore the cooling duty for both heat exchangers is limited by the freezing point of the CO2stream, which enters the second multistream heat exchanger. The trend lines of the distillation type of CO2CPU are also depicted in Fig. 4, but due to the purification process at higher values of specific compression duty. Again the specific power consumption forms a slight minimum with respect to precompression pressure p1. This trend results from the interaction between the external cooling cycle and the pressure p1 which also affects the
Fig. 4. Specific compression power.
distillation column. Higher precompression pressures p1 provoke a decrease in cooling agent demand. Compared to the double flash type 1 case, for an economic operation of this CO2CPU T2 shall be kept as high as possible. As also seen in Fig. 4 the specific compression duty of a conventional 5-stage compressor as it is depicted in Fig. 3 is lower than in the distillation type but higher than the double flash type. Since not only carbon dioxide but all impurities in the flue gas stream are compressed to final pressure p3 the compression duty related to the carbon dioxide is higher than in purification unit 1. This shows the importance of the Dynamis recommendation that CO2 content in the compressed gas stream shall be above 95%. As a summary CO2CPU type 1 can achieve a specific compression power of approximately 0.52 GJ/t sep. CO2 and type 2 about 0.70 GJ/t sep. CO2 at the optimum operation point. A conventional 5-stage compressor lies in the range of 0.54 GJ/t sep. CO2. The determined optimum values of p1 and T2 for each CO2CPU in Fig. 4 do not correspond to optimum values regarding separation efficiency and CO2-purity (see Section 6.3). 6.2. Specific cooling duty With regard to specific cooling duty, the characteristics of both types of compression units follow qualitatively the curves of power consumption (see Fig. 5). Again in type 1 an increase in precompression pressure p1 will lead to a decrease in cooling duty by passing a local maximum. At type 2 an increase in p1 leads to a slight minimum in the amount of required cooling water. In addition it was observed, that the characteristics of the specific cooling duty of both CO2CPU types follows steeper descents as they are doing at specific compression duty. Compared with a conventional 5-stage compressor the specific cooling duty is higher for both separation types (see Fig. 5).
Table 3 Flue gas specifications.
Coal-max Coal-min Natural gas
CO2 (mol%)
H2O (mol%)
Ar (mol%)
N2 (mol%)
O2 (mol%)
SO2 (mol%)
SO3 (mol%)
p0 (bar)
T0 (°C)
76.378 72.426 61.211
1.336 1.074 1.019
3.109 2.807 3.707
11.340 14.162 26.549
7.826 9.522 7.514
0.011 0.009 0.000
6 105 4 105 0.000
0.90915 0.97285 0.98355
13.2 11.0 10.4
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decreases. At intermediate precompression pressures p1 a local minimum appears which is followed by a local maximum. This behavior follows again from the fact that condensation starts in the first multi stream heat exchanger 1-HX1. At CO2CPU type 2 a higher precompression pressure p1 will also lead to higher separation efficiency. Both types are showing nearly the same behavior in separation efficiency. Due to the fact that a distillation column is provided in this CO2CPU, the carbon dioxide purity varies marginally with pressure p1 and lies in the range between 99.98 mol% and 99.99 mol% (see Fig. 6). This high purity in combination with high separation efficiency is counterbalanced by the higher specific energy and cooling demand as seen in Figs. 5 and 6. CO2CPU type 2 requires a pressure p1 of more than 28 bar to achieve separation efficiencies of 90 wt% or greater, type 1 CO2CPU reaches a
Fig. 5. Specific cooling duty.
6.3. CO2-purity and separation efficiency Further meaningful results are the purity of the carbon dioxide product stream and the separation efficiency. The separation efficiency gsep is calculated by:
_ m
gsep ¼ _co2 sep mco2 0
ð12Þ
_ co2 0 stands for the initial CO2 mass flow in the satuIn Eq. (12) m _ co2 sep indicates the separated CO2 mass rated flue gas stream and m flow. In Fig. 6 the separation efficiency gsep as well as the achieved CO2 purity is depicted for type 1 and type 2 CO2CPU. For the double flash type 1 the separation efficiency increases with increasing pressure p1, whereas carbon dioxide content of the product stream
Fig. 6. CO2-purity and separation efficiency.
Fig. 7. Spec. compression power and cooling duty for different firing and load cases.
Fig. 8. CO2 purity and separation efficiency for different firing and load cases.
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separation efficiency of nearly 90 wt% only at pressure p1 of more than 25 bar. By planning an economical CO2CPU of type 1 or 2 this behavior and the results from specific compression duty have to be taken into account. The results from the conventional 5-stage compressor without purification are not depicted in Fig. 6. However, it is obvious that the separation efficiency is nearly 100% in case of a conventional compressor, whereas the CO2 purity is more or less constant over the compressor. Due to the Dynamis recommendation, CO2 purity lower than 95% is not advisable for the carbon dioxide transportation, this type of compressor was not included in further simulations. 7. Variable flue gas conditions Since a hard coal fired power plant also operates in part load to satisfy the actual demand of electricity, the carbon dioxide compression and purification unit has to work in part load too. During start-up procedure or in case of malfunction of the pulverized coal firing the power plant operates with natural gas. Three of these cases were considered within this work. Pulverized coal firing at nominal load (coal-max). Pulverized coal firing at part load (coal-min). Natural gas firing at part load (natural gas).
In case of part load as well as in case of natural gas firing the composition of the saturated oxy-fuel derived flue gas will change (see Table 3). As before all three firing cases were compared in specific compression power, specific cooling duty, separation efficiency and purity of the separated carbon dioxide product stream. Here, due to the results from the characteristics of every type of separation, the operating pressures were defined to minimize the compression work at a separation efficiency gsep > 90 wt%. Therefore the operating point for CO2CPU type 1 is chosen at p1 = 30 bar and T2 = 30 °C, for type 2 the most efficient operation point lies at p1 = 28 bar and T2 = 35 °C. Final pressure at the CO2 outlet stream is fixed for both types with p3 = 120 bar. The chosen operating points are marked by the rhombs in Fig. 4. The results for different part loads are depicted in Figs. 7 and 8. The filled bars in the two figures are showing the results where kij-mixing parameters in Peng–Robinson equation of state were considered. The hatched bars in the background of each figure are showing the results for the same load cases where the kij-mixing parameters were neglected (see Section 8). Fig. 7 states that decreasing carbon dioxide content in the desiccated flue gas commonly leads to higher values in specific compression work and specific cooling duty. Both CO2 separation units are showing this behavior. As expected from the trend lines
Table 4 Detailed results of double flash type CO2CPU separation plant at different load cases. Stream #
1
Mass flow (kg/s) Coal-max Coal-min Natural gas
95.2000 54.6000 32.5000
94.6204 54.3373 32.3448
55.6339 25.9255 6.2356
19.7755 14.5987 13.3360
19.2109 13.8131 12.7732
74.8449 39.7386 19.0088
0.9092 0.9729 0.9836
30.0000 30.0000 30.0000
19.8789 17.7840 16.4867
30.0000 30.0000 30.0000
8.9439 8.0345 7.8694
120.0000 120.0000 120.0000
Temperature (°C) Coal-max Coal-min Natural gas
13.2000 11.0000 10.4000
30.0000 29.9999 30.0000
35.0000 36.0000 37.0000
15.3902 14.4454 14.9592
55.4999 55.5000 55.5000
36.5991 35.5223 35.9472
CO2 (wt%) Coal-max Coal-min Natural gas
82.4120 79.2715 70.0712
82.9168 79.6548 70.4073
97.0814 97.7733 97.9660
31.0853 31.3400 32.0445
95.2517 96.7112 97.0070
96.6118 97.4041 97.3216
H2O (wt%) Coal-max Coal-min Natural gas
0.6088 0.4812 0.4775
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
Ar (wt%) Coal-max Coal-min Natural gas
3.0470 2.7888 3.8519
3.0657 2.8022 3.8704
0.6519 0.3208 0.2964
11.7741 9.4076 8.8274
1.0913 0.4786 0.4398
0.7647 0.3757 0.3927
N2 (wt%) Coal-max Coal-min Natural gas
7.7900 9.8665 19.3453
7.8377 9.9142 19.4381
0.8969 0.9319 1.2134
33.6914 33.9661 44.8987
1.3244 1.3533 1.7526
1.0067 1.0784 1.5757
O2 (wt%) Coal-max Coal-min Natural gas
6.1420 7.5777 6.2541
6.1796 7.6143 6.2841
1.3694 0.9462 0.5242
23.4493 25.2863 14.2294
2.3326 1.4524 0.8006
1.6166 1.1222 0.7099
SO2 (ppm) Coal-max Coal-min Natural gas
0.0002 0.0143 0.0000
0.0002 0.0143 0.0000
0.0003 0.0276 0.0000
0.0000 0.0001 0.0000
0.0000 0.0045 0.0000
0.0002 0.0196 0.0000
SO3 (ppm) Coal-max Coal-min Natural gas
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
0.0000 0.0002 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0001 0.0000
Pressure (bar) Coal-max Coal-min Natural gas
3
5
11
13
18
262
S. Posch, M. Haider / Fuel 101 (2012) 254–263
in Section 6 internal cooled double flash separation unit requires at every load case a lower specific compression work and cooling duty compared to the distillation unit. Due to the adjustment of all variables the difference in separation efficiency (Fig. 8) is nearly the same in all three load cases between the two analyzed separation units. The separation efficiency does not vary strongly as long as coal is fired in the oxy-fuel steam generator, but drops under the threshold of 90 wt% in the part load case. Once the operation changes to natural gas firing, the separation efficiency decreases to values of around 80 wt% in both CO2-compression units. In this case another operating point of the compression unit would have to be adjusted in order to keep the separation efficiency at values greater than 90 wt%. Fig. 8 also shows the purity of the separated carbon dioxide stream. In case of double flash separation decreasing carbon dioxide content in the saturated flue gas slightly leads to decreasing CO2 purity too. In case of separation with a distillation column the raw gas composition does not have appreciable influence on the carbon dioxide purity in the flue gas stream. Due to different separation facility also the product stream composition varies with separation type and firing case. As listed in Table 1 the main focus lies primary on SOx concentration, since
there is no NOx assumed in the saturated flue gas stream. Further, if the product stream is provided for EOR or EGR attention has to be paid to the O2 content as well. In Tables 4 and 5 the results for O2 and SOx concentration are listed for every load case. As seen in Fig. 8 the CO2 content greater than 95 mol% can be achieved by both CO2CPU’s. If the product stream is provided for storage in saline aquifers the oxygen content in the product stream is within threshold. However, in the case of EOR or EGR the desired O2 after Table 1 can only be achieved by a distillation column. With regard to toxicity the SOx content smaller than 100 ppm cannot be achieved by any of the two observed compression and separation units in the coal-min part load case. This indicates that in the analyzed case the desulphurization unit upstream the CO2CPU would need to be upgraded in order to fulfill the requirements concerning toxicity and hazard in case of a sudden leakage of a CO2-pipeline (see Table 1). Numerical results for variable flue gas conditions are listed in Table 4 for type 1 CO2CPU and in Table 5 for the distillation type of the compression and separation unit. These two tables contain mass flow, pressure, temperature and chemical composition of the main streams in each plant. Stream numbers listed in Tables 4 and 5 correspond with those in Figs. 1 and 2.
Table 5 Detailed results of distillation type CO2CPU separation plant at different load cases. Stream #
1
Mass flow (kg/s) Coal-max Coal-min Natural gas
95.2000 54.6000 32.5000
94.6204 54.3373 32.3448
174.1493 89.9181 33.5620
23.9126 16.4127 14.3743
150.2367 73.5054 19.1877
70.7079 37.9246 17.9705
70.7079 37.9246 17.9705
0.9092 0.9729 0.9836
28.0000 28.0000 28.0000
28.0000 28.0000 28.0000
1.0000 1.0000 1.0000
19.8135 19.7701 19.2035
5.7850 5.7839 5.3150
120.0000 120.0000 120.0000
Temperature (°C) Coal-max Coal-min Natural gas
13.2000 11.0000 10.4000
35.0011 35.0000 28.0021
54.4985 54.4982 54.4995
21.0688 21.1756 25.4345
55.5000 55.5000 55.5000
53.5000 53.5000 55.5000
36.7398 36.7276 36.7411
CO2 (wt%) Coal-max Coal-min Natural gas
82.4120 79.2715 70.0712
82.9168 79.6548 70.4073
88.0660 85.2429 69.9089
32.4056 32.6930 33.4127
96.9252 96.9766 97.2499
99.9991 99.9786 99.9988
99.9991 99.9786 99.9988
H2O (wt%) Coal-max Coal-min Natural gas
0.6088 0.4812 0.4775
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
Ar (wt%) Coal-max Coal-min Natural gas
3.0470 2.7888 3.8519
3.0657 2.8022 3.8704
2.1683 2.0547 3.9624
12.1302 9.2770 8.7088
0.5827 0.4421 0.4066
0.0001 0.0001 0.0002
0.0001 0.0001 0.0002
N2 (wt%) Coal-max Coal-min Natural gas
7.7900 9.8665 19.3453
7.8377 9.9142 19.4381
5.2633 6.9909 19.6462
31.0129 32.8225 43.7387
1.1649 1.2231 1.5974
0.0001 0.0002 0.0005
0.0001 0.0002 0.0005
O2 (wt%) Coal-max Coal-min Natural gas
6.1420 7.5777 6.2541
6.1796 7.6143 6.2841
4.5024 5.7107 6.4825
24.4512 25.2074 14.1398
1.3272 1.3574 0.7461
0.0004 0.0005 0.0005
0.0004 0.0005 0.0005
SO2 (wt%) Coal-max Coal-min Natural gas
0.0002 0.0143 0.0000
0.0002 0.0143 0.0000
0.0000 0.0007 0.0000
0.0000 0.0000 0.0000
0.0000 0.0009 0.0000
0.0003 0.0205 0.0000
0.0003 0.0205 0.0000
SO3 (wt%) Coal-max Coal-min Natural gas
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
Pressure (bar) Coal-max Coal-min Natural gas
3
7
11
12
16
19
S. Posch, M. Haider / Fuel 101 (2012) 254–263
8. Influence of kij-mixing parameters For all calculations the kij mixing parameters from Peng–Robinson equation of state were taken from [11]. To demonstrate the importance of choosing the appropriate kij value for each combination of substances, the flue gas band from Section 7 was calculated again, where kij parameters were set to zero (see Eq. (9)). The results are overlaid with the bar charts from Section 7 and are marked with hatched bars (Figs. 7 and 8). As seen in Fig. 7 the effect of missing kij parameters does not influence the specific compression power and specific cooling duty noticeably. By observing Fig. 8 a neglect of kij parameters commonly shifts the separation efficiency to higher values. In case of double flash separation the larger difference compared to the distillation type results from the higher impurity concentration in the CO2 stream. To ensure a certain separation efficiency appropriate values for kij are essential. An obverse behavior can be seen in CO2-purity in Fig. 8 too. Here, neglect of kij parameters at double flash purification unit leads to lower CO2 content in the product stream. The effect of missing kij parameters at CO2CPU working with the distillation column (type 2) is some orders of magnitude lower than it is for the double flash unit. The results of the current work could not be revalidated by experiments. Nevertheless it is assumed that the simulations with kij – 0 have higher accuracy. The importance of choosing the adequate values for kij, especially in case of industrial utilization of the separated CO2, is demonstrated. 9. Conclusions Within this work two different types of carbon dioxide compression and purification units for an oxy-fuel derived flue gas have been presented. A double flash separation unit was compared with a separation unit based on rectification. Both types were also compared with a conventional 5-stage compressor for carbon dioxide. Within this comparison specific compression power, specific cooling duty, separation efficiency and CO2 purity were calculated for different operation pressures. Furthermore three different power plant loads were assumed and both types of CO2CPU were exposed to the different loads. To conclude the influence of kij mixing parameters for Peng–Robinson equation of state on the results was shown. For both types of CO2 separation it has to be ensured, that nowhere in the plant the temperature of the concentrated CO2 stream drops below the triple point temperature of 56.55 °C. Since the separation unit operates at elevated pressures a temperature below the triple point temperature will lead to the formation of solid CO2. In flash separation the specific compression and cooling duty decreases with increasing precompression pressure p1. The condensation temperature T2 has to be kept as low as possible in order to minimize the specific compression and cooling duty. The separation efficiency rises with higher pressure p1 and is above 90 wt% at values p1 > 25 bar. At low pressures p1 no condensation happens in the first multi stream heat exchanger (1-HX1) which in turn increases the size of the second multi stream heat exchanger (2-HX1). In rectification separation again a high precompression pressure p1 is important in order to keep specific compression power and cooling duty low. Condensation temperature T2 shall be kept as
263
high as possible to minimize these values too. Further high precompression will lead to high separation efficiency, whereby the CO2 product quality is not sensible to a variation of p1. A conventional 5-stage compressor without purification option is not adequate for oxy-fuel derived flue gases. When the CO2CPU receives different flue gas compositions the specific compression power as well as the specific cooling duty increases with decreasing carbon dioxide content in the saturated flue gas stream. Both types of CO2CPU are showing this behavior. By switching from coal to natural gas firing the separation efficiency drops to values around 80 wt%. Also the CO2 purity at the outlet of compression unit type 1 follows this trend and sinks with lower CO2 content in the saturated flue gas stream. Outlet purity of CO2CPU type 2 is not sensible to various CO2 contents in the flue gas stream, since a distillation column is provided in the plant. In summary type 1 double flash separation unit has the lower power and cooling requirement. Type 2 (separation by rectification) achieves higher purity at nearly the same separation efficiency, but at the cost of almost 30% increase of power and cooling duty. The kij mixing parameters for Peng–Robinson equation of state have low influence on specific compression power and cooling duty but are crucial for the calculation of CO2-purity and separation efficiency. References [1] Intergovernmental Panel on Climate Change (IPCC). IPCC Special report on carbon dioxide capture and storage. Cambridge, New York, Melbourne, Madrid, Cape Town, Singapore, Sào Paulo: Cambridge University Press; 2005. [2] International Energy Agency (IEA). World energy outlook 2009 – executive summary. [3] Gibbins J, Chalmers H. Carbon capture and storage. Energy Policy 2008;36:4317–22. [4] Darde A, Prabhakar R, Tranier J-P, Perrin N. Air separation and flue gas compression and purification units for oxy-coal combustion systems. Energy Procedia 2009;1:527–34. [5] Pipitone G, Bolland O. Power generation with CO2 capture: technology for CO2purification. Int J Greenhouse Gas Control 2009;3:528–34. [6] Ritter R, Kutzschbach A, Stoffregen T. Energetische Bewertung einer CO2Kompressions- und Reinigungsanlage für den Oxyfuel-Prozess am Beispiel einer Demonstrationsanlage. From: Beckmann M, Hurtado A. Kraftwerkstechnik – Sichere und nachhaltige Energieversorgung – TK Verlag Thomé-Kozmiensky, Neuruppin; 2009. [7] White V, Torrente-Murciano L, Sturgeon D, Chadwick D. Purification of oxyfuel-derived CO2. Energy Procedia 2009;1:399–406. [8] Eldevik F, Graver B, Torbergsen LE, Saugerud OT. Development of a guideline for safe, reliable and cost efficient transmission of CO2 in pipelines. Energy Procedia 2009;1:1579–85. [9] de Visser E, Hendriks C, Barrio M, Mølnvik MJ, de Koeijer G, Liljemark S, et al. Dynamis CO2 quality recommendations. Int J Greenhouse Gas Control 2008;2:478–84. [10] Santos S. Summary notes on ‘What is the implication of CO2 quality in its design and engineering of pipeline transport’. Presentation within ‘Working group on quality of CO2 capture from oxyfuel combustion power plant’, Stockholm; 2008. [11] Eggers R, Köpke D. Phase equilibria measurements and their application for the CO2 separation from CO2 rich gases. Presentation within IEAGHG international oxy-combustion network, Yokohama; 2008. [12] White V, Rodney JA. Purification of carbon dioxide. United States Patent Application Publication US 2008/0176174 A1. [13] Elsam A/S, Kinder Morgan CO2 Company L.P., New Energy Statoil: special report on delivery of carbon dioxide. [accessed 28.09.10]. [14] Peng D-Y, Robinson DB. A new two-constant equation of state. Ind Eng Chem Fundam 1976;15(1). [15] Pitzer KS, Lippmann DZ, Curl RF, Huggins CM, Petersen DE, et al. The volumetric and thermodynamic properties of fluids. II. Compressibility factor, vapor pressure and entropy of vaporization. J Am Chem Soc 1955;77(13):3433–40.
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Optimization of CO2 compression and purification units (CO2CPU) for CCS power plants Sebastian Posch ⇑, Markus Haider Institute of Energy Systems and Thermodynamics, Vienna University of Technology, Getreidemarkt 9/E302, A-1060 Vienna, Austria
a r t i c l e
i n f o
Article history: Received 28 September 2010 Received in revised form 23 July 2011 Accepted 26 July 2011 Available online 9 August 2011 Keywords: CCS, carbon capture and storage CO2 compression CO2 quality Oxy-fuel Purification
a b s t r a c t Oxy-fuel power plants are among the currently known major carbon capture and storage (CCS) technologies those which produce the lowest carbon dioxide (CO2) purity CO2-stream. As a consequence, the oxy-fuel technology has the highest requirement towards CO2 purification. In the current paper two different purification processes are modeled in Aspen Plus™ based on a Peng–Robinson property method with kij mixing coefficients. Both separation processes are based on phase separation technique. The first one is equipped with two flash columns and the second one includes a distillation column. Both plants require a dehydration plant for water removal. For each process the impact of main design parameters on performance features such as specific power requirement, specific cooling duty, separation efficiency and CO2 purity are analyzed, including variations in flue gas composition, plant load and kij mixing parameters. The results were compared to a conventional 5-stage CO2 compressor. Ó 2011 Elsevier Ltd. All rights reserved.
1. Introduction Nowadays, many researchers agree that anthropogenic greenhouse gases (GHG) provoke a change in climate. Since 1750 the global atmospheric concentrations of carbon dioxide, methane and nitrous oxide increased vehemently due to human activities. The global increase in CO2 is supposed to be mainly caused by fossil fuel use and land use [1]. According to the outlook of the International Energy Agency (IEA) [2] fossil fuels still are going to play a major role in the next decades to satisfy the world energy demand. Among the fossil fuels coal shows the highest reserves, however coal also has the highest specific carbon dioxide emissions within the fossil fuels. In order to combine the satisfaction in world energy demand and the reduction of greenhouse gases different strategies have to be followed over the next decades simultaneously [2]. These are Increase in energy efficiency. Renewable energy. Carbon capture and storage (CCS). The idea behind carbon capture and storage is to separate the carbon dioxide from flue gases. The captured CO2 is further
⇑ Corresponding author. Tel.: +43 1 58801 30211, mobile: +43 650 5711989; fax: +43 1 58801 30299. E-mail address: [email protected] (S. Posch). 0016-2361/$ - see front matter Ó 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.fuel.2011.07.039
compressed and transported to different storage sites, which are saline aquifers or depleted oil and gas fields. Furthermore the separated and compressed carbon dioxide can increase oil or gas field extraction by enhanced oil or gas recovery (EOR/EGR). In all storage options, the compressed stream of CO2 has to fulfill particular purity requirements. They are most stringent in case of EOR/EGR. Carbon capture and storage can be classified into three different technologies. Post combustion capture. Pre combustion capture. Oxy-fuel technology. A detailed description of each technology can be found in many literature sources, i.e. [3]. Even if the separation approach is completely different at all three technologies, they have a CO2 compressor station in common to make an economic transport of CO2 possible. Within this paper the compression and purification of an oxy-fuel derived flue gas stream was considered. The primary goal was to generate the characteristic diagrams of two different CO2-compression and purification units (CO2CPU) with respect to specific energy and cooling water consumption, CO2-purity and separation efficiency. These values were compared with a conventional 5-stage compressor for CO2. In addition the influence of different power plant loads and fuels was analyzed. Finally also the influence of different kij mixing parameters from Peng–Robinson equation of state was considered.
S. Posch, M. Haider / Fuel 101 (2012) 254–263
255
Nomenclature
a ac a b kij _ CO2 sep m _ CO2 0 m n
gsep p patt prep pc R
constant, describing the attractive interaction (J m3 mol2) substance specific constant in the attractive interaction (J m3 mol2) temperature dependent function to adjust the attractive interaction (–) constant, describing the repulsive interaction (m3 mol1) mixing parameter (–) mass flow of the purified CO2 (kg s1) mass flow of the raw flue gas stream (kg s1) amount of species in the mixture (–) mass related separation efficiency (–) actual pressure (Pa) attraction term of the actual pressure (Pa) repulsion term of the actual pressure (Pa) critical pressure (Pa) universal gas constant (8.314 J mol1 K1)
2. Previous work Since oxy-fuel combustion for power plant has not reached full scale, the main focus right now lies on research and development. Regarding to compression and purification units, several papers and patents were published in recent times. Darde et al. [4] presented in their work some basic considerations on CO2CPU. Pipitone and Bolland [5], Ritter et al. [6] as well as White et al. [7] presented and compared carbon dioxide compression and purification units for oxy-fuel combustion in their work. Furthermore Eldevik et al. [8] and de Visser et al. [9] presented first considerations and guidelines regarding CO2 product quality. Santos [10] as well as Eggers and Köpke [11] presented appropriate values for kij mixing parameters for Peng–Robinson equation of state with respect to carbon dioxide. This work mainly focuses on the separation plants which were suggested in Ritter et al. [6] and White et al. [12]. Small modifications were done to achieve high reliability of each CO2CPU. 3. Purity requirements Flue gas composition varies with the fuel used and carbon dioxide separation technology. In case of oxy-fuel combustion of coal the derived flue gas consists mainly of carbon dioxide (CO2) and water (H2O). Due to air leakage and excess of oxygen during the combustion also nitrogen (N2) and oxygen (O2) are present in oxy-fuel derived flue gas. As long as coal is fired in the boiler the flue gas will also contain sulfur oxides (SOx), nitrogen oxides (NOx), traces of mercury and other organic or inorganic components [1]. In order to establish the whole chain of CCS, the separated carbon dioxide has to be compressed, transported and stored. Due to environmental regulations, technical, economical and/or safety reasons [9] published some basic guidelines concerning impurities in a carbon dioxide stream which is provided for storage or EOR and EGR. These guidelines are the result of basic considerations on the following points [9]: Safety and toxicity of substances present in the CO2 stream. Avoidance of free water formation. Avoidance of hydrate formation. Avoidance of corrosion. Reduction of the CO2 volume.
T Tc Tr Vm y
x
actual temperature (K) critical temperature (K) reduced temperature (–) molar volume (m3 mol1) mole fraction (–) acentric factor (–)
Subscripts i component i in the mixture (–) j component j in the mixture (–) ii value for pure fluid i (–) ij interaction between component i and component j in the mixture (–) jj value for pure fluid j (–) 0 at the inlet of the CO2CPU (–) 1 at position 1 in the CO2CPU (–) 2 at position 2 in the CO2CPU (–) 3 at position 3 in the CO2CPU (–)
The specifications can be seen in Table 1. Additionally to the Dynamis guideline two other quality specifications are included in Table 1 for EOR projects in the United States of America [13,9]. In order to minimize the specific compression work and cooling duty per separated carbon dioxide the CO2 content shall reach at least 95%. Since the presence of free water enhances corrosion and hydrate formation the maximum H2O content shall not exceed 500 ppm, in order to avoid free water formation [9]. The entire content of non condensable gases such as argon (Ar), hydrogen (H2) and nitrogen (N2) is set smaller than 5%. The non condensable gas H2 shall be minimized in the CO2 stream, since it requires a very high specific compression work and represents a considerable sink of energy. With respect to toxicity the contents of nitric oxide (NOx) and sulfur oxide (SOx) shall be kept under the threshold of 100 ppm, in order to avoid health effects in a case of a sudden leakage [9]. Moreover, the tolerable oxygen (O2) content varies, if the CO2 is stored in saline aquifers or if it is used for EOR and EGR. In case of enhanced oil or gas recovery the oxygen content shall not reach the limit of 100 ppm. Pipitone and Bolland [5] state that higher concentrations in oxygen may cause severe problems: Overheating at the injection point. Oxidation in the reservoir with higher oil viscosity and increased extraction cost. Increased biological growth with unknown effects on oil production. 4. Equation of state (EOS) For all simulations in the present publication the Peng–Robinson equation of state [14] was chosen as the most appropriate equation for the calculation of fluid properties in the purification process. The Peng–Robinson equation is a cubic equation of state based on the theorem of corresponding states, which basically says that the compressibility factor of a pure fluid can be expressed by its critical pressure and temperature as well as its acentric factor. Derived from the van-der-Waals equation of state, the Peng–Robinson equation of state consists of a repulsion term prep and an attraction term patt. Both terms are describing the actual pressure in the system:
P ¼ prep þ patt
ð1Þ
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Table 1 Different specifications of CO2-composition after purification. US pipeline quality specifications [13]
Weyburn EOR project [1]
Dynamis [9]
CO2 Ar CxHy
>95% – <5%
>96% – <0.7%
CO H2O H2S N2 NOx O2
– 0.4805 g/Nm3 10 – 200 ppm <4% – <10 ppm
<1000 ppm <20 ppm <9000 ppmv <300 ppm – <50 ppm
SOx Temperature
– <50 °C
– <50 °C
>95.5% <4% <4% (saline aquifers) <2%vol (EOR) <2000 ppm <500 ppm <200 ppm <4% <100 ppm <4% (saline aquifers) <100–1000 ppm (EOR) <100 ppm –
For the Peng–Robinson equation the parameters a(T) and b are introduced to get an adequate description of the vapor–liquid properties of the fluid. The main difference to the van-der-Waals equation of state is the temperature dependency of the attraction term a(T). The Peng–Robinson equation of state results to
P¼
RT aðTÞ V m b V 2m þ 2V m b b2
ð2Þ
where a(T) is defined by:
aðTÞ ¼ ac aðTÞ
ð3Þ
The constants ac and b in Eqs. (2) and (3) are related to the critical point of the substance.
ac ¼ 0:4572
R2 T 2c
pc RT c b ¼ 0:07780 pc
ð4Þ ð5Þ
The temperature dependency of the attraction term is again described by an empirical formula [14].
sffiffiffiffiffi!!2 T 2 aðTÞ ¼ 1 þ ð0:37464 þ 1:54226 x 0:26992 x Þ 1 Tc ð6Þ In Eq. (6) x designates the acentric factor, introduced by Pitzer et al. [15], which represents the vapor pressure curve and is specific to each substance and calculated by:
x ¼ 1:000 log10 ðp0r ÞT r ¼0:7
ð7Þ
In Eq. (7) ðp0r ÞT r ¼0:7 designates the reduced saturation vapor pressure at the reduced temperature Tr = 0.7. For pure carbon dioxide the critical values are taken as follows: pc = 7.375E6 Pa, Tc = 304.184 K and x = 0.239. 4.1. Homogeneous, multi component mixtures The Peng–Robinson equation of state (2) allows the calculation of the liquid and the gas phase properties for a pure fluid. To describe vapor and liquid properties of a homogenous, multi component mixture the Peng–Robinson equation of state has to be extended by mixing rules. A number of mixing rules can be found in the literature; however, most of them do not base on a strict theoretical approach but results empirically from multi component measurements. The simplest empirical approach for a cubic equation of state is described in this section. To achieve good predictions of the liquid and gaseous properties, the attraction and the repulsion term for the Peng–Robinson equation (2) have to be adjusted. The repulsive term for the
mixture follows from the arithmetic average of the repulsive term for each species multiplied by its mole fraction.
b¼
n X
yi bi
ð8Þ
i¼1
In Eq. (8) bi for each species i is calculated by Eq. (5). The attraction term for multi component mixtures has a quadratic dependency of the mole fraction and is calculated by:
a¼
n X n X i¼1
yi yj
pffiffiffiffiffiffiffiffiffiffi aii ajj ð1 kij Þ
ð9Þ
j¼1
For better results of vapor–liquid properties equation (9) is extend by the binary mixing parameter kij. These mixing parameters have typically very small values; however, they have a remarkable influence on the results of the calculation. It is further possible to introduce a temperature dependency of the binary mixing parameter kij described by: ð2Þ
ð1Þ
ð2Þ
kij ðTÞ ¼ kij þ kij T þ
kij
ð10Þ
T
For all values of kij the following relationship (11) is fulfilled.
kij ¼ kji
ð11Þ
Eqs. (1)–(11) are implemented in the AspenPlus™ process simulation software. The critical point properties for each species as well as the acentric factor are provided by the AspenProperties™ databank. kij mixing parameters are also provided by AspenProperties™ where possible, however they can be manipulated by the user if more adequate values are present. 5. Purification process Within this paper two different CO2 compression and purification units for an oxy-fuel derived flue gas stream were modeled in AspenPlus™ and compared to a conventional compression unit without purification of the CO2 stream. The Peng–Robinson model was chosen as property method for fugacity and thermal state equations. Mixing parameters kij were taken from [11] and are listed in Table 2. Both CO2CPU’s operate on the basis of phase Table 2 kij mixing parameters for Peng–Robinson equation of state [11]. Species 1
Species 2
kij-Value
CO2 CO2 CO2 CO2
Ar O2 N2 SO2
0.1230 0.1116 0.0115 0.0559
S. Posch, M. Haider / Fuel 101 (2012) 254–263
separation techniques, where type 1 is working with flash separation and type 2 has a distillation column, which is equipped with six equilibrium stages. In every case the oxy-fuel derived flue gas is saturated with water before entering the compression and purification unit. The intercooling duty at each type of compression and purification unit as well as for the conventional CO2 compressor has to be delivered by the cooling water of the power plant and by additional cooling facilities. Polytropic efficiency of each compressor stage was assumed with 0.8. All three types of CO2CPU deliver a compressed CO2 stream at final pressure p3. The dehydration plant is simulated as a conventional separator without any energy input, only the compression duty for the additional water in the flue gas to pressure p1 is considered in the simulation. For a save and undisturbed operation of the compression and purification unit it is absolutely necessary to avoid ice formation in the CO2CPU. Since no liquefaction is possible at pressures below the triple point, temperatures below 56.55 °C have to be avoided in order to prohibit the formation of solid carbon dioxide in the CO2CPU.
257
CO2 rich liquid stream. Both streams, the liquid and the gaseous one, are connected to the second multi stream heat exchanger again to act as the cooling agent. The CO2 poor stream passes the first multi stream heat exchanger before it leaves the CO2 compression unit. Since this stream is still at elevated pressure and at low temperature it can be used as a cooling agent somewhere else in the oxy-fuel process (i.e. in the air separation unit). After reheating this stream it can be further expanded in a gas turbine to deliver electric power before it leaves the plant at atmospheric pressure. This benefit was not considered in this work. The CO2 rich stream passes an adiabatic throttle (3-TH1), expands and enters the multi stream heat exchanger 2-HX1 again. Both liquid streams from the two flash columns act again as the cooling agent for multi stream heat exchanger 1-HX1. The CO2-stream coming from the second flash column is recompressed and connected with the former liquid stream from the first flash column 1-FL1. The resulting high concentrated CO2 stream enters the final two stage compression train with intercooling. The CO2 stream is compressed to 80 bar and cooled down to 25 °C where it is in supercritical dense state and can be pumped up to final pressure p3.
5.1. Type 1: Double flash separation – internal cooling 5.2. Type 2: Separation by distillation – external and internal cooling Compression and purification unit 1 is an auto-refrigerated system and is shown in Fig. 1. The flue gas stream enters the precompression train and is compressed to p1. In order to reduce work requirement, the precompression is done in three stages with intercooling down to 25 °C flue gas temperature after each intercooler. Every intercooler is equipped with a condensate trap to avoid the inlet of water droplets in the next compressor stage. After precompression the flue gas stream passes the dehydration plant, where the water content is reduced to 20 ppm in order to fulfill the Dynamis recommendation. Further the flue gas is partly condensed at temperature T2 in the first multi stream heat exchanger 1-HX1 (stream 3 in Fig. 1). The liquid–gas mixture then reaches the first flash column (1-FL1). The gaseous part, dilute in carbon dioxide, is further cooled to 54.5 °C in the second multi stream heat exchanger (2-HX1), where again the gaseous stream condenses partly into a 2-phase mixture. In a second flash column (2-FL1) the stream is again separated in a CO2 poor vapor and a
In the second compression and purification unit the two flash columns from type 1 are replaced by a distillation column in order to increase the purity of the compressed CO2 stream (Fig. 2). Again the saturated raw gas from the oxy-fuel power plant is precompressed to p1, passes the dehydration plant and the multi stream heat exchanger 1-HX1 where it is cooled down to temperature T2 and enters the distillation column 2-D1. The vaporous product of 2-D1 is partly condensed (2-HX1) to a vapor fraction of 0.75, where the cooling duty is delivered by an external ammonia cooling cycle. The two phase stream then is separated. The liquid part runs back in 2-D1. The vaporous part reenters 1-HX1 where it is partly condensed at 54.5 °C. The vapor–liquid mixture is separated in flash column 3-FL1. The gaseous stream passes an adiabatic throttle, where the stream is cooled down to 55.5 °C and reenters the multi stream heat exchanger. Since the stream still comprises cooling capacity it is again expanded in a second adiabatic throttle and
Fig. 1. Double flash compression and purification unit – internal cooling.
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Fig. 2. Compression and purification unit with distillation column – external and internal cooling.
reenters the multi stream heat exchanger once again. After passing the heat exchanger the waste stream acts as the cooling agent for the recompression of the liquid branch from flash column 3-FL1. Analogous to type 1 compression unit this waste stream comprises cooling potential, which can be taken into account in the air separation unit. Again this benefit was not considered in this work. The liquid stream from 3-FL1 also serves as a cooling agent in 1-HX1 until it is reconnected with the original flue gas stream. The liquid product of the distillation column is partly evaporated by the external ammonia cycle to a vapor fraction of 0.45, where the resulting vaporous part reenters the distillation column. The residual liquid product passes an adiabatic throttle, enters the multi stream heat exchanger and is then compressed to 68 bar and finally pumped to the final pressure p3. 5.3. Type 3: Standard five stage compressor Both types of the mentioned CO2CPU’s are compared to a conventional five stage compression train for carbon dioxide as
depicted in Fig. 3. This standard multistage compressor has again an intercooler behind each stage. The first three stages are equipped with a condensate trap after the intercooler in order to avoid erosion in the following stages due to water droplets. After the third compressor stage the precompressed flue gas passes through the dehydration plant. From there the dehydrated carbon dioxide stream enters the final compression stages, where it is compressed to pressure p3. 6. Characteristics of the CO2CPU’s First point of interest in this work was to generate the characteristics of each CO2 compression and purification unit and to minimize for each process separately the required power and amount of cooling water. The discharge pressure p1 of the precompression train was varied at both types of CO2CPU. For both types also the outlet temperature of the first multistream heat exchanger T2 was varied. In a first calculation the discharge pressure p1 was varied between 13 and 32 bar. In addition the condensation
Fig. 3. Conventional 5-stage compressor with intercooling.
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temperature T2 lies between 20 and 30 °C for CO2CPU type 1 and between 35 and 42.5 °C for CO2CPU type 2. To determine the characteristics of each type of CO2CPU a saturated oxy-fuel derived flue gas enters the precompression train. The composition is specified as ‘‘coal-max’’ in Table 3. The flue gas composition was calculated in a detailed retrofit study for an existing coal power plant. Older coal fired plants operate at higher excess oxygen than modern state of the art technology. In addition, parasitic air intrusion in retrofit situations will be higher than in tailor made oxy-fuel steam generators. As a result, the O2-purity of the oxy-fuel product stream is lower and the requirements for CO2CPU are higher in retrofit than in Greenfield oxy-fuel CCS. 6.1. Specific compression power First task of this work was to determine the trend of specific compression power for each CO2CPU. The results for all types are depicted in Fig. 4. For double flash compression unit type 1 the specific compression power is a strong nonlinear function of the precompression pressure p1. In Fig. 4 precompression pressure starts at 13 bar and ends up at 32 bar. At lower pressures the required cooling demand cannot be provided in the heat exchangers due to p, T-behavior of CO2 where at higher pressures no condensation will result at pressures p = 80 bar at the end of the compression unit. The set of T2-isotherms in Fig. 4 shows two local minima and one local maximum in specific work duty by varying pressure p1 for CO2CPU type 1. The local minimum at lower pressures of p1 results from two contrariwise effects in the compression train. With increasing pressure p1 a larger part of the gaseous CO2stream condensates in the multi stream heat exchanger 2-HX1 which leads to a decrease in specific compression duty. On the other hand an increase in mass flow leads to higher compression work in the second compression train, since the pressure ratio over the adiabatic throttle increases with higher pressures p1. The local maximum on the T2-isotherms in Fig. 4 results from the two installed flash columns in CO2CPU type 1. Since the condensation temperature is a function of pressure p1, partial condensation starts in the first multi stream heat exchanger at elevated pressures p1. Due to absence of recompression in the liquid branch of the first flash column this stream directly enters the second compression train after passing the first heat exchanger. Therefore the specific compression duty starts to decrease again at elevated pressures p1. At lower condensation temperatures T2 a second local minimum can be observed in Fig. 4. This minimum again is caused by the same reason than the first minimum due to the two contrary effects as explained before. To keep the specific compression duty as low as possible, the condensation temperature T2 in the first heat exchanger has to be kept as low as possible too. The limiting case arises from the fact, that the condensation temperature in the second heat exchanger and therefore the cooling duty for both heat exchangers is limited by the freezing point of the CO2stream, which enters the second multistream heat exchanger. The trend lines of the distillation type of CO2CPU are also depicted in Fig. 4, but due to the purification process at higher values of specific compression duty. Again the specific power consumption forms a slight minimum with respect to precompression pressure p1. This trend results from the interaction between the external cooling cycle and the pressure p1 which also affects the
Fig. 4. Specific compression power.
distillation column. Higher precompression pressures p1 provoke a decrease in cooling agent demand. Compared to the double flash type 1 case, for an economic operation of this CO2CPU T2 shall be kept as high as possible. As also seen in Fig. 4 the specific compression duty of a conventional 5-stage compressor as it is depicted in Fig. 3 is lower than in the distillation type but higher than the double flash type. Since not only carbon dioxide but all impurities in the flue gas stream are compressed to final pressure p3 the compression duty related to the carbon dioxide is higher than in purification unit 1. This shows the importance of the Dynamis recommendation that CO2 content in the compressed gas stream shall be above 95%. As a summary CO2CPU type 1 can achieve a specific compression power of approximately 0.52 GJ/t sep. CO2 and type 2 about 0.70 GJ/t sep. CO2 at the optimum operation point. A conventional 5-stage compressor lies in the range of 0.54 GJ/t sep. CO2. The determined optimum values of p1 and T2 for each CO2CPU in Fig. 4 do not correspond to optimum values regarding separation efficiency and CO2-purity (see Section 6.3). 6.2. Specific cooling duty With regard to specific cooling duty, the characteristics of both types of compression units follow qualitatively the curves of power consumption (see Fig. 5). Again in type 1 an increase in precompression pressure p1 will lead to a decrease in cooling duty by passing a local maximum. At type 2 an increase in p1 leads to a slight minimum in the amount of required cooling water. In addition it was observed, that the characteristics of the specific cooling duty of both CO2CPU types follows steeper descents as they are doing at specific compression duty. Compared with a conventional 5-stage compressor the specific cooling duty is higher for both separation types (see Fig. 5).
Table 3 Flue gas specifications.
Coal-max Coal-min Natural gas
CO2 (mol%)
H2O (mol%)
Ar (mol%)
N2 (mol%)
O2 (mol%)
SO2 (mol%)
SO3 (mol%)
p0 (bar)
T0 (°C)
76.378 72.426 61.211
1.336 1.074 1.019
3.109 2.807 3.707
11.340 14.162 26.549
7.826 9.522 7.514
0.011 0.009 0.000
6 105 4 105 0.000
0.90915 0.97285 0.98355
13.2 11.0 10.4
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decreases. At intermediate precompression pressures p1 a local minimum appears which is followed by a local maximum. This behavior follows again from the fact that condensation starts in the first multi stream heat exchanger 1-HX1. At CO2CPU type 2 a higher precompression pressure p1 will also lead to higher separation efficiency. Both types are showing nearly the same behavior in separation efficiency. Due to the fact that a distillation column is provided in this CO2CPU, the carbon dioxide purity varies marginally with pressure p1 and lies in the range between 99.98 mol% and 99.99 mol% (see Fig. 6). This high purity in combination with high separation efficiency is counterbalanced by the higher specific energy and cooling demand as seen in Figs. 5 and 6. CO2CPU type 2 requires a pressure p1 of more than 28 bar to achieve separation efficiencies of 90 wt% or greater, type 1 CO2CPU reaches a
Fig. 5. Specific cooling duty.
6.3. CO2-purity and separation efficiency Further meaningful results are the purity of the carbon dioxide product stream and the separation efficiency. The separation efficiency gsep is calculated by:
_ m
gsep ¼ _co2 sep mco2 0
ð12Þ
_ co2 0 stands for the initial CO2 mass flow in the satuIn Eq. (12) m _ co2 sep indicates the separated CO2 mass rated flue gas stream and m flow. In Fig. 6 the separation efficiency gsep as well as the achieved CO2 purity is depicted for type 1 and type 2 CO2CPU. For the double flash type 1 the separation efficiency increases with increasing pressure p1, whereas carbon dioxide content of the product stream
Fig. 6. CO2-purity and separation efficiency.
Fig. 7. Spec. compression power and cooling duty for different firing and load cases.
Fig. 8. CO2 purity and separation efficiency for different firing and load cases.
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separation efficiency of nearly 90 wt% only at pressure p1 of more than 25 bar. By planning an economical CO2CPU of type 1 or 2 this behavior and the results from specific compression duty have to be taken into account. The results from the conventional 5-stage compressor without purification are not depicted in Fig. 6. However, it is obvious that the separation efficiency is nearly 100% in case of a conventional compressor, whereas the CO2 purity is more or less constant over the compressor. Due to the Dynamis recommendation, CO2 purity lower than 95% is not advisable for the carbon dioxide transportation, this type of compressor was not included in further simulations. 7. Variable flue gas conditions Since a hard coal fired power plant also operates in part load to satisfy the actual demand of electricity, the carbon dioxide compression and purification unit has to work in part load too. During start-up procedure or in case of malfunction of the pulverized coal firing the power plant operates with natural gas. Three of these cases were considered within this work. Pulverized coal firing at nominal load (coal-max). Pulverized coal firing at part load (coal-min). Natural gas firing at part load (natural gas).
In case of part load as well as in case of natural gas firing the composition of the saturated oxy-fuel derived flue gas will change (see Table 3). As before all three firing cases were compared in specific compression power, specific cooling duty, separation efficiency and purity of the separated carbon dioxide product stream. Here, due to the results from the characteristics of every type of separation, the operating pressures were defined to minimize the compression work at a separation efficiency gsep > 90 wt%. Therefore the operating point for CO2CPU type 1 is chosen at p1 = 30 bar and T2 = 30 °C, for type 2 the most efficient operation point lies at p1 = 28 bar and T2 = 35 °C. Final pressure at the CO2 outlet stream is fixed for both types with p3 = 120 bar. The chosen operating points are marked by the rhombs in Fig. 4. The results for different part loads are depicted in Figs. 7 and 8. The filled bars in the two figures are showing the results where kij-mixing parameters in Peng–Robinson equation of state were considered. The hatched bars in the background of each figure are showing the results for the same load cases where the kij-mixing parameters were neglected (see Section 8). Fig. 7 states that decreasing carbon dioxide content in the desiccated flue gas commonly leads to higher values in specific compression work and specific cooling duty. Both CO2 separation units are showing this behavior. As expected from the trend lines
Table 4 Detailed results of double flash type CO2CPU separation plant at different load cases. Stream #
1
Mass flow (kg/s) Coal-max Coal-min Natural gas
95.2000 54.6000 32.5000
94.6204 54.3373 32.3448
55.6339 25.9255 6.2356
19.7755 14.5987 13.3360
19.2109 13.8131 12.7732
74.8449 39.7386 19.0088
0.9092 0.9729 0.9836
30.0000 30.0000 30.0000
19.8789 17.7840 16.4867
30.0000 30.0000 30.0000
8.9439 8.0345 7.8694
120.0000 120.0000 120.0000
Temperature (°C) Coal-max Coal-min Natural gas
13.2000 11.0000 10.4000
30.0000 29.9999 30.0000
35.0000 36.0000 37.0000
15.3902 14.4454 14.9592
55.4999 55.5000 55.5000
36.5991 35.5223 35.9472
CO2 (wt%) Coal-max Coal-min Natural gas
82.4120 79.2715 70.0712
82.9168 79.6548 70.4073
97.0814 97.7733 97.9660
31.0853 31.3400 32.0445
95.2517 96.7112 97.0070
96.6118 97.4041 97.3216
H2O (wt%) Coal-max Coal-min Natural gas
0.6088 0.4812 0.4775
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
Ar (wt%) Coal-max Coal-min Natural gas
3.0470 2.7888 3.8519
3.0657 2.8022 3.8704
0.6519 0.3208 0.2964
11.7741 9.4076 8.8274
1.0913 0.4786 0.4398
0.7647 0.3757 0.3927
N2 (wt%) Coal-max Coal-min Natural gas
7.7900 9.8665 19.3453
7.8377 9.9142 19.4381
0.8969 0.9319 1.2134
33.6914 33.9661 44.8987
1.3244 1.3533 1.7526
1.0067 1.0784 1.5757
O2 (wt%) Coal-max Coal-min Natural gas
6.1420 7.5777 6.2541
6.1796 7.6143 6.2841
1.3694 0.9462 0.5242
23.4493 25.2863 14.2294
2.3326 1.4524 0.8006
1.6166 1.1222 0.7099
SO2 (ppm) Coal-max Coal-min Natural gas
0.0002 0.0143 0.0000
0.0002 0.0143 0.0000
0.0003 0.0276 0.0000
0.0000 0.0001 0.0000
0.0000 0.0045 0.0000
0.0002 0.0196 0.0000
SO3 (ppm) Coal-max Coal-min Natural gas
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
0.0000 0.0002 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0001 0.0000
Pressure (bar) Coal-max Coal-min Natural gas
3
5
11
13
18
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in Section 6 internal cooled double flash separation unit requires at every load case a lower specific compression work and cooling duty compared to the distillation unit. Due to the adjustment of all variables the difference in separation efficiency (Fig. 8) is nearly the same in all three load cases between the two analyzed separation units. The separation efficiency does not vary strongly as long as coal is fired in the oxy-fuel steam generator, but drops under the threshold of 90 wt% in the part load case. Once the operation changes to natural gas firing, the separation efficiency decreases to values of around 80 wt% in both CO2-compression units. In this case another operating point of the compression unit would have to be adjusted in order to keep the separation efficiency at values greater than 90 wt%. Fig. 8 also shows the purity of the separated carbon dioxide stream. In case of double flash separation decreasing carbon dioxide content in the saturated flue gas slightly leads to decreasing CO2 purity too. In case of separation with a distillation column the raw gas composition does not have appreciable influence on the carbon dioxide purity in the flue gas stream. Due to different separation facility also the product stream composition varies with separation type and firing case. As listed in Table 1 the main focus lies primary on SOx concentration, since
there is no NOx assumed in the saturated flue gas stream. Further, if the product stream is provided for EOR or EGR attention has to be paid to the O2 content as well. In Tables 4 and 5 the results for O2 and SOx concentration are listed for every load case. As seen in Fig. 8 the CO2 content greater than 95 mol% can be achieved by both CO2CPU’s. If the product stream is provided for storage in saline aquifers the oxygen content in the product stream is within threshold. However, in the case of EOR or EGR the desired O2 after Table 1 can only be achieved by a distillation column. With regard to toxicity the SOx content smaller than 100 ppm cannot be achieved by any of the two observed compression and separation units in the coal-min part load case. This indicates that in the analyzed case the desulphurization unit upstream the CO2CPU would need to be upgraded in order to fulfill the requirements concerning toxicity and hazard in case of a sudden leakage of a CO2-pipeline (see Table 1). Numerical results for variable flue gas conditions are listed in Table 4 for type 1 CO2CPU and in Table 5 for the distillation type of the compression and separation unit. These two tables contain mass flow, pressure, temperature and chemical composition of the main streams in each plant. Stream numbers listed in Tables 4 and 5 correspond with those in Figs. 1 and 2.
Table 5 Detailed results of distillation type CO2CPU separation plant at different load cases. Stream #
1
Mass flow (kg/s) Coal-max Coal-min Natural gas
95.2000 54.6000 32.5000
94.6204 54.3373 32.3448
174.1493 89.9181 33.5620
23.9126 16.4127 14.3743
150.2367 73.5054 19.1877
70.7079 37.9246 17.9705
70.7079 37.9246 17.9705
0.9092 0.9729 0.9836
28.0000 28.0000 28.0000
28.0000 28.0000 28.0000
1.0000 1.0000 1.0000
19.8135 19.7701 19.2035
5.7850 5.7839 5.3150
120.0000 120.0000 120.0000
Temperature (°C) Coal-max Coal-min Natural gas
13.2000 11.0000 10.4000
35.0011 35.0000 28.0021
54.4985 54.4982 54.4995
21.0688 21.1756 25.4345
55.5000 55.5000 55.5000
53.5000 53.5000 55.5000
36.7398 36.7276 36.7411
CO2 (wt%) Coal-max Coal-min Natural gas
82.4120 79.2715 70.0712
82.9168 79.6548 70.4073
88.0660 85.2429 69.9089
32.4056 32.6930 33.4127
96.9252 96.9766 97.2499
99.9991 99.9786 99.9988
99.9991 99.9786 99.9988
H2O (wt%) Coal-max Coal-min Natural gas
0.6088 0.4812 0.4775
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
Ar (wt%) Coal-max Coal-min Natural gas
3.0470 2.7888 3.8519
3.0657 2.8022 3.8704
2.1683 2.0547 3.9624
12.1302 9.2770 8.7088
0.5827 0.4421 0.4066
0.0001 0.0001 0.0002
0.0001 0.0001 0.0002
N2 (wt%) Coal-max Coal-min Natural gas
7.7900 9.8665 19.3453
7.8377 9.9142 19.4381
5.2633 6.9909 19.6462
31.0129 32.8225 43.7387
1.1649 1.2231 1.5974
0.0001 0.0002 0.0005
0.0001 0.0002 0.0005
O2 (wt%) Coal-max Coal-min Natural gas
6.1420 7.5777 6.2541
6.1796 7.6143 6.2841
4.5024 5.7107 6.4825
24.4512 25.2074 14.1398
1.3272 1.3574 0.7461
0.0004 0.0005 0.0005
0.0004 0.0005 0.0005
SO2 (wt%) Coal-max Coal-min Natural gas
0.0002 0.0143 0.0000
0.0002 0.0143 0.0000
0.0000 0.0007 0.0000
0.0000 0.0000 0.0000
0.0000 0.0009 0.0000
0.0003 0.0205 0.0000
0.0003 0.0205 0.0000
SO3 (wt%) Coal-max Coal-min Natural gas
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0001 0.0000
0.0000 0.0001 0.0000
Pressure (bar) Coal-max Coal-min Natural gas
3
7
11
12
16
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8. Influence of kij-mixing parameters For all calculations the kij mixing parameters from Peng–Robinson equation of state were taken from [11]. To demonstrate the importance of choosing the appropriate kij value for each combination of substances, the flue gas band from Section 7 was calculated again, where kij parameters were set to zero (see Eq. (9)). The results are overlaid with the bar charts from Section 7 and are marked with hatched bars (Figs. 7 and 8). As seen in Fig. 7 the effect of missing kij parameters does not influence the specific compression power and specific cooling duty noticeably. By observing Fig. 8 a neglect of kij parameters commonly shifts the separation efficiency to higher values. In case of double flash separation the larger difference compared to the distillation type results from the higher impurity concentration in the CO2 stream. To ensure a certain separation efficiency appropriate values for kij are essential. An obverse behavior can be seen in CO2-purity in Fig. 8 too. Here, neglect of kij parameters at double flash purification unit leads to lower CO2 content in the product stream. The effect of missing kij parameters at CO2CPU working with the distillation column (type 2) is some orders of magnitude lower than it is for the double flash unit. The results of the current work could not be revalidated by experiments. Nevertheless it is assumed that the simulations with kij – 0 have higher accuracy. The importance of choosing the adequate values for kij, especially in case of industrial utilization of the separated CO2, is demonstrated. 9. Conclusions Within this work two different types of carbon dioxide compression and purification units for an oxy-fuel derived flue gas have been presented. A double flash separation unit was compared with a separation unit based on rectification. Both types were also compared with a conventional 5-stage compressor for carbon dioxide. Within this comparison specific compression power, specific cooling duty, separation efficiency and CO2 purity were calculated for different operation pressures. Furthermore three different power plant loads were assumed and both types of CO2CPU were exposed to the different loads. To conclude the influence of kij mixing parameters for Peng–Robinson equation of state on the results was shown. For both types of CO2 separation it has to be ensured, that nowhere in the plant the temperature of the concentrated CO2 stream drops below the triple point temperature of 56.55 °C. Since the separation unit operates at elevated pressures a temperature below the triple point temperature will lead to the formation of solid CO2. In flash separation the specific compression and cooling duty decreases with increasing precompression pressure p1. The condensation temperature T2 has to be kept as low as possible in order to minimize the specific compression and cooling duty. The separation efficiency rises with higher pressure p1 and is above 90 wt% at values p1 > 25 bar. At low pressures p1 no condensation happens in the first multi stream heat exchanger (1-HX1) which in turn increases the size of the second multi stream heat exchanger (2-HX1). In rectification separation again a high precompression pressure p1 is important in order to keep specific compression power and cooling duty low. Condensation temperature T2 shall be kept as
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high as possible to minimize these values too. Further high precompression will lead to high separation efficiency, whereby the CO2 product quality is not sensible to a variation of p1. A conventional 5-stage compressor without purification option is not adequate for oxy-fuel derived flue gases. When the CO2CPU receives different flue gas compositions the specific compression power as well as the specific cooling duty increases with decreasing carbon dioxide content in the saturated flue gas stream. Both types of CO2CPU are showing this behavior. By switching from coal to natural gas firing the separation efficiency drops to values around 80 wt%. Also the CO2 purity at the outlet of compression unit type 1 follows this trend and sinks with lower CO2 content in the saturated flue gas stream. Outlet purity of CO2CPU type 2 is not sensible to various CO2 contents in the flue gas stream, since a distillation column is provided in the plant. In summary type 1 double flash separation unit has the lower power and cooling requirement. Type 2 (separation by rectification) achieves higher purity at nearly the same separation efficiency, but at the cost of almost 30% increase of power and cooling duty. The kij mixing parameters for Peng–Robinson equation of state have low influence on specific compression power and cooling duty but are crucial for the calculation of CO2-purity and separation efficiency. References [1] Intergovernmental Panel on Climate Change (IPCC). IPCC Special report on carbon dioxide capture and storage. Cambridge, New York, Melbourne, Madrid, Cape Town, Singapore, Sào Paulo: Cambridge University Press; 2005. [2] International Energy Agency (IEA). World energy outlook 2009 – executive summary. [3] Gibbins J, Chalmers H. Carbon capture and storage. Energy Policy 2008;36:4317–22. [4] Darde A, Prabhakar R, Tranier J-P, Perrin N. Air separation and flue gas compression and purification units for oxy-coal combustion systems. Energy Procedia 2009;1:527–34. [5] Pipitone G, Bolland O. Power generation with CO2 capture: technology for CO2purification. Int J Greenhouse Gas Control 2009;3:528–34. [6] Ritter R, Kutzschbach A, Stoffregen T. Energetische Bewertung einer CO2Kompressions- und Reinigungsanlage für den Oxyfuel-Prozess am Beispiel einer Demonstrationsanlage. From: Beckmann M, Hurtado A. Kraftwerkstechnik – Sichere und nachhaltige Energieversorgung – TK Verlag Thomé-Kozmiensky, Neuruppin; 2009. [7] White V, Torrente-Murciano L, Sturgeon D, Chadwick D. Purification of oxyfuel-derived CO2. Energy Procedia 2009;1:399–406. [8] Eldevik F, Graver B, Torbergsen LE, Saugerud OT. Development of a guideline for safe, reliable and cost efficient transmission of CO2 in pipelines. Energy Procedia 2009;1:1579–85. [9] de Visser E, Hendriks C, Barrio M, Mølnvik MJ, de Koeijer G, Liljemark S, et al. Dynamis CO2 quality recommendations. Int J Greenhouse Gas Control 2008;2:478–84. [10] Santos S. Summary notes on ‘What is the implication of CO2 quality in its design and engineering of pipeline transport’. Presentation within ‘Working group on quality of CO2 capture from oxyfuel combustion power plant’, Stockholm; 2008. [11] Eggers R, Köpke D. Phase equilibria measurements and their application for the CO2 separation from CO2 rich gases. Presentation within IEAGHG international oxy-combustion network, Yokohama; 2008. [12] White V, Rodney JA. Purification of carbon dioxide. United States Patent Application Publication US 2008/0176174 A1. [13] Elsam A/S, Kinder Morgan CO2 Company L.P., New Energy Statoil: special report on delivery of carbon dioxide.