IGCC–EPI: Decentralized concept of a highly load-flexible IGCC power plant for excess power integration

Applied Energy 104 (2013) 869–879

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IGCC–EPI: Decentralized concept of a highly load-flexible IGCC power plant for excess power integration Alexander Buttler ⇑, Christian Kunze, Hartmut Spliethoff Institute for Energy Systems, Technische Universität München, Germany

h i g h l i g h t s " A new concept for integration of excess power in IGCC power plants was developed. " It consists of an electrolysis plant and a methanation process. " Simulations of the concept in Aspen Plus show a superior operation range. " Synergies between the processes result in a high overall storage efficiency.

a r t i c l e

i n f o

Article history: Received 8 October 2012 Received in revised form 26 November 2012 Accepted 27 November 2012 Available online 4 January 2013 Keywords: IGCC Electrolysis Energy storage Excess power Poly-generation

a b s t r a c t The growing share of renewable energy generation eventually could lead to increased fluctuations in power supply and to negative residual loads. Therefore flexible power plants as well as significant long-term energy storage capacity are required. In this paper, an Integrated Gasification Combined Cycle (IGCC) power plant is combined with an electrolysis plant and substitute natural gas (SNG) synthesis. In this way a highly load-flexible IGCC plant is developed for excess power integration (EPI) from renewable energy sources or inflexible conventional power plants. The proposed IGCC–EPI concept is modeled in Aspen Plus. The decentralized power plant has a capacity of 125 MWth and runs on hard coal. An extensive parameter study has demonstrated the superior operation range from +67 MW to 253 MW of net power output/input. Synergies between the IGCC–EPI power plant, the methanation process and the electrolysis indicate a maximum overall efficiency of 40.1% from coal and excess energy to SNG and back to electricity. Ó 2012 Elsevier Ltd. All rights reserved.

1. Introduction The long-term transition of current energy systems, which are mainly based on fossil fuels, into renewable energy systems will result in increased fluctuations due to the weather-dependent feed-in of wind and solar power. Therefore, the utilization of controllable power plants will decrease. However, flexible mid-load and peak-load power stations are still required as back-up in case of low power generation from volatile energy sources. Additionally, large-scale energy storage is required to balance out weekly and seasonal fluctuations. In Germany, for example, the government aims to raise the share of renewable energies in gross electricity consumption to 80% by 2050 [1], which will lead to an expected excess power generation in the order of 26–53 TW h [2,3]. For long-term energy storage, only chemical storages are suitable due to their high energy density. Electrical energy is stored as hydrogen produced by electrolysis or in an additional step as sub⇑ Corresponding author. Tel.: +49 (0)89 289 16264. E-mail address: [email protected] (A. Buttler). 0306-2619/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.apenergy.2012.11.066

stitute natural gas (SNG). The production of SNG allows an unlimited feed-in into the natural gas network and allows existing storage capacities to be used without further costs. Moreover, it offers an energy density three times larger than hydrogen stored at the same pressure. The disadvantages are the need for a carbon source, lower efficiency and higher specific costs due to the additional conversion step. In this context, the combination with an Integrated Gasification Combined Cycle (IGCC) power plant offers promising potential by using resulting synergies. The integration of an electrolysis plant into a gasification plant has been investigated in [4] for hydrogen production, in [5] for the production of methanol and in [6,7] for SNG production. IGCC concepts with poly-generation and CCS have been investigated extensively [8– 10]. However, little has been published about the integration of an electrolysis plant into an IGCC power plant with poly-generation to form an IGCC storage plant. The potential of energy storage, load flexibility of the plant concept, conversion efficiency and the impact of synergies within the process are the focus of the investigation. After giving a theoretical introduction to the subsystems of the IGCC storage plant, the modeling and verification of the subsys-

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Nomenclature area of electrode (m2) specific energy consumption of the electrolyzer (kW h/ Nm3H2 ) EASU specific energy consumption of the ASU (kW h/Nm3O2 ) E_ exergy flow (kW) F Faraday constant (F = 96485 C/mol) f11, f12, f21, f22 empirical parameters of the Faraday efficiency equation DG Gibbs energy change of the reaction (J/mol) DH Enthalpy change of reaction (J/mol) HHV higher heating value (kW h/Nm3) I current (A) kIF improvement factor (–) LHV lower heating value (kW h/Nm3) _ m mass flow (kg/s) nc number of cells connected in series per module (–) n_ molar flow rate (mol/s) P power (kW) p pressure (bar) r, s, t1, t2, t3 empirical parameters of the I–U-curve DS Entropy change of reaction (J mol1 K1) mean operating time of the electrolyzer (s) top T temperature (°C) A EEL

tems is presented. This is followed by the concept design of the highly load-flexible IGCC–EPI power plant and an analysis of different operation cases. 2. Theory 2.1. IGCC power plant An IGCC plant enables the utilization of cheap solid fuels in a highly efficient combined cycle and basically consists of three subsystems: gas production, gas conditioning and gas utilization. The simplified process scheme for the IGCC plant configuration is presented in Fig. 1. The gasification island consists of a dry feed entrained gasifier (1450 °C, 33 bar) and a gas quench. The gasifier has a thermal capacity of 125 MW and is fed by hard coal. Oxygen with a purity level of 98% is provided by a low-pressure cryogenic air separation unit (ASU). In the gas quench, the raw synthesis gas is quenched to 900 °C by recirculating cold, solid-free syngas [11]. The sensible heat is used to generate high and intermediate pressure steam, which can be integrated into the steam cycle of the combined cycle power plant. The cooled gas is then cleaned of sul-

U Urev V W x z

voltage (V) reversible cell voltage (V) volume (m3) work (kJ) mole fraction (–) number of electrons transferred per reaction (z = 2)

Greek letters g energtic efficiency (–) gF Faraday efficiency (–) f exergetic efficiency (–) Subscripts ASU air separation unit Aux auxiliaries C compressor cc combined cycle CH4 methane EL electrolysis plant PG purge gas T turbine th thermal

fur components and partially of CO2 by a chemical methyldiethanolamine (MDEA) wash, which can achieve gas purities of 4 ppmv H2S and COS [12]. Due to the small size of the power plant, it is assumed that the construction of a CO2 pipeline is economically not reasonable, and no CCS is applied. To be applicable to the gas turbine the hydrogen rich cleaned syngas is diluted with hot water and the nitrogen from the ASU to limit the formation of thermal NOx. The hot exhaust from the gas turbine is used in a heat recovery steam generator (HRSG) to generate additional steam. For maximum efficiency a 3-pressure-level HRSG is applied although a 2-pressure-level HRSG might be more reasonable from an economic point of view, which should be investigated in further work.

2.2. Electrolysis Water electrolysis is an electrochemical process to decompose water into hydrogen and oxygen by passing a direct current between two electrodes separated by an electrolyte. The overall reaction taking place is:

Fig. 1. Simplified process scheme of an IGCC power plant without CCS.

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H2 O

Electrolysis

!

H2 ¼

1 O2 ; 2

DH0 ¼ 286

kJ mol

ð2:1Þ

with the enthalpy change of reaction DH0 given at standard conditions (25 °C, 1,013 bar). The enthalpy change of reaction DH is a measure of the minimum total energy that has to be supplied, whereby part of the energy must be electrical (equal to the Gibbs free energy change DG) and the rest can be thermal energy Q, which equals the product of the process temperature T and the entropy change DS:

DH ¼ DG þ DQ ¼ DG þ T DS

ð2:2Þ

The dependency of the total energy consumption DH as well as the electrical part DG and thermal part TDS from the temperature for an ideal cell is shown in Fig. 2. The electric energy demanded by the electrolysis reaction DG decreases as temperature increases, while the thermal energy demand TDS increases, resulting in an almost constant total energy consumption DH. This means that at higher temperatures electrical energy can be replaced by thermal energy. The minimal cell voltage for electrolysis, achieved in a reversible cell where the required heat is additionally supplied, is given by the reversible cell voltage:

U rev ¼

DG zF

ð2:3Þ

where DG is the change in Gibbs energy, z is the number of electrons transferred per reaction (z = 2) and F represents the Faraday’s constant. Due to internal losses, the actual cell voltage is higher. It can be expressed as the sum of the reversible cell voltage Urev and the overvoltages caused by ohmic resistance (Uohm), limitations in electrode kinetics (Uact) and mass transport (Ucon), respectively [13]:

U ¼ U rev þ U ohm þ U act þ U con

ð2:4Þ

As shown in Fig. 3, the cell voltage rises with increasing cell current due to higher losses. This results in the phenomenon that electrolysis plants reach higher efficiencies when they are operated at part load. Moreover, the cell voltage U as well as the reversible cell voltage Urev decreases with increasing temperature. The impact of the pressure (not shown in Fig. 3) is limited. The reversible voltage increases slightly at higher pressures, e.g. Urev = 1.229 V at standard conditions versus Urev = 1.294 V at a pressure of 30 bar. For a given cell current, the hydrogen production rate n_ H2 of an electrolyzer module with the number of cells connected in series nc can be calculated according to Faraday’s law:

Fig. 2. Total energy consumption DH, electrical demand DG and thermal demand TDS of an ideal electrolysis process as function of the temperature at standard pressure (1.013 bar) [13].

Fig. 3. Typical I–U-curves for a low-temperature electrolyzer cell [14].

n_ H2 ¼ gF

nc I zF

ð2:5Þ

Losses of parasitic currents along the gas ducts are considered by the Faraday efficiency gF, which is defined as the ratio between the actual and the theoretical production rate of hydrogen [14]. The parasitic currents increase with decreasing electrical resistance. Therefore high current densities and low temperatures lead to a higher resistance and accordingly high Faraday efficiencies. The overall efficiency of an electrolyzer can be calculated as the energy stored in the produced hydrogen divided by the electrical energy input PEL:

gHHV ¼

HHV  V_ H2 P EL

ð2:6Þ

where HHV is the higher heating value of H2 (HHV = 3.54 kW h/ Nm3) and V_ H2 is the volume flow of H2. The efficiency is usually given in kilowatt hours per normal cubic meter (at standard conditions) of dry hydrogen produced (kW h/Nm3). Only the energy stored chemically as hydrogen is taken into account, while the use of oxygen is neglected. Table 1 presents the two major electrolysis designs that are relevant for near-term scenarios. The high-temperature electrolysis technology (or solid oxide electrolysis) is neglected due to its early stage of development. However it should be mentioned that this technology has the potential to reduce electrical energy consumption in comparison to state-of-the-art low-temperature electrolysis technologies because of the high temperatures of 700–900 °C (see Fig. 2). Therefore a high-temperature electrolysis IGCC-concept should also be investigated in future work. The low-temperature electrolytic cells consist of two electrodes in separated half cells and an ion-conducting electrolyte, which is usually an aqueous solution of 20–30% KOH (alkaline) or a polymer membrane (PEM). Due to increased corrosion at higher temperatures, the maximum temperature for PEM and alkaline electrolysis is limited to about 80–100 °C [15]. For both PEM and alkaline electrolysis, large plants are realized by connecting several modules in parallel. They reach hydrogen and oxygen purity levels of 99.9% and 99.7% respectively without post-treatment [13] and can be operated at high pressures. Due to the efficient electrochemical compression, an efficiency advantage is expected for pressurized electrolyzers compared to atmospheric electrolyzers with an additional mechanical compressor [16]. On the other hand, the gas ducts must be purged with inert gas when the electrolyzer is shut down for a longer time, to prevent the mixing of the product gases by diffusion across the diaphragm [15]. This results in losses that increase with rising operation pressure (e.g. in [17] a loss of 4% per year is reported for a solar-powered 7-bar electrolyzer).

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Table 1 Main technologies of water electrolysis. Name

Alkaline

PEM

2OH ! 12 O2 þ H2 O þ 2e 2H2 O þ 2e ! H2 þ 2OH

H2 O ! 12 O2 þ 2Hþ þ 2e

Cathode Operation parameters T (°C) Max. pressure (bar) Current density (A/cm2) Min. part-load (%)

40–90 [15] 30 [13] 0.2–0.4 [15] 5–25 [13]

20–100 [15] 85 [13] 0.6–2 [15] 0–5 [13]

State of the art Efficiencya (%) (HHV) Module power (MW) Life timea Investment costs (€/kW)

70–82 [13] 3.5 [36] 30–40 [36] 800–1500 [42] (pressure  + 20%)

71 [40] 0.17 [41] 20 [40] 2000–6000 [42]

Scheme (adapted from [15])

Electrode reactions Anode

a

2Hþ þ 2e ! H2

Electrolysis module only (without auxiliary consumers)

Today, only alkaline electrolysis modules are available in the MW range due to their lower investment costs. PEM electrolysis offers excellent dynamic behavior with a high load change rate and a control range from 0% to 100%. The poorer dynamic properties of the alkaline electrolysis mainly result from the fact that water is consumed on the anode side and produced on the cathode side (see reactions in Table 1). To keep the lye concentration constant on both sides, the lye streams of the cathode and anode side must be mixed before entering the module. In this context, to prevent a contamination of the product gases (explosion risk), large separator tanks are required to ensure a sufficient residence time for gas bubbles to separate from the lye by their uplift [18]. On the one hand, this limits the load change rate due to the huge thermal capacity. On the other hand, the minimal part-load operation is determined by the contamination. However, alkaline electrolysis offers a sufficiently fast dynamic behavior which is proofed in several hydrogen storage pilot plants (e.g. [19,20]). Moreover, the part-load limitation can be neglected for large plants with several parallel modules. Due to the fact that only alkaline electrolysis modules are available in the MW range, as well as its maturity and its sufficient response to dynamic power input, this technology has been selected for this paper. 2.3. SNG synthesis The SNG synthesis is an exothermal process in which CO, CO2 and H2 are converted into CH4 through a nickel catalyst via the following reactions:

CO methanation : 3H2 þ CO $ CH4 þ H2 O  206 MJ=kmol

ð2:7Þ

CO2 methanation : 4H2 þ CO2 $ CH4 þ 2H2 O  165 MJ=kmol

ð2:8Þ

The primary methanation reaction is the CO conversion, whereas the conversion of CO2 does not occur as long as CO is present [21]. The SNG synthesis is favored at low temperatures and

high pressures because otherwise the CO-shift reaction starts to dominate over the CO methanation. The temperature range is determined by the stability of the catalysts applied and is limited to about 700 °C due to sintering of the catalyst [22,23]. The lower temperature is limited to about 250 °C due to decreasing catalyst activity, increasing adsorption of catalyst poisons and carbonyl formation. As the reactions are highly exothermal, proper cooling is required to ensure the maximum temperature limit. This also affects the maximum pressure because of the resulting high heat production per volume [21]. Today, quite a number of methanation processes are commercially available, for example from Lurgi [24], Haldor Topsoe (TREMP) [25] and Davy Process Technology (HICOM) [26]. As they are similar in design (using adiabatic fixed-bed reactors connected in series) only a simplified scheme of the TREMP process is shown in Fig. 4. The typical operation temperature is between 250 and 650 °C at pressures ranging from 15 to 80 bar [21]. To produce gas with a high methane content, the temperature of the last stage must be as low as possible (250–300 °C) [23]. The temperature rise caused by the reaction heat of the exothermic process is controlled by multiple reactors with intermediate cooling and gas recycling. The released heat is used to generate high-pressure superheated steam at up to 540–600 °C [22,23]. As a final step, the product gas is dried to fulfill quality requirements. 3. Modeling and concept design 3.1. Electrolysis The model of the electrolysis plant is based on an empirical model by [14] that was originally developed for dynamic simulations. It is based on a real electrolysis plant being able to emulate losses, the dependency on temperature and pressure as well as part-load operation. The most relevant equations for the model are summarized in Table 2. At the core of the simulation are the empirical functions of the I–U curve (Eq. (5.1)), the reversible cell voltage (Eq. (5.2)) and the Faraday efficiency (Eq. (5.3)). Empirical

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Fig. 4. Simplified scheme of the TREMP methanation process [43].

Table 2 Equations of the electrolysis model (own derivations and modified equations from [14,44]). Name Cell voltage

Equations

Unit rI A

UðT; p; lÞ ¼ U rev ðT; pÞ þ þ

3 =T slogðt1 þt2 =Tþt A 3

Reversible voltage

U rev ðT; pÞ ¼ 1:229  0:85  10

Faraday efficiency

gF ¼ f

Specific energy consumption

ðI=AÞ2 2 11 þf12 TþðI=AÞ

(5.1)

I þ 1Þ 5

ðT  25Þ þ 4:3085  10

ðT 

P 273:15Þ½1:5lnð1:013 Þ

ðf21 þ f22 TÞ

5 EEL ¼ 2UF g  1:239  10

V

(5.2)

V

(5.3)

–

(5.4)

kW h Nm3

(5.5)

kW

F

Purge gas loss

P PG ðpÞ ¼

Electrolysis power H2 production rate

P EL ¼ ½U  I  nc  kIF   gDC þ P PG ðpÞ þ P Aux n_ H2 ¼ gF nzFc I n_ H2 O ¼ n_ H2 ¼ 2n_ O2

H2O, H2 and O2 rate

pg =pV PG ðpg Þ t op

 EEL

data is derived from the 350 kW electrolyzer of the HYSOLAR project [27]. The I–U curve was identified based on the provided data (Fig. 5). The empirical parameters of the Faraday efficiency were used from the model by Ulleberg [14] because the published Faraday efficiencies of the HYSOLAR electrolyzer [27] are in the same range. Moreover, a model was developed for the losses caused by the purging of the gas ducts when the electrolyzer is shut down.

(5.6) (5.7)

kW mol s mol s

(5.8)

The relative amount of these losses is dependent on the mean operating time top of the electrolyzer. The model is based on the purge gas volume VPG of 2.3 Nm3 at a pressure of pg = 9 bar given in [27] and the ideal gas law (pV = const.). Furthermore, the potential for improving the electrolyzer performance by using activated electrodes, which is stated to be in the range of 13–18% [27], is considered by way of an improvement factor kIF. Additionally, the consumption of auxiliary components (instrumentation, control and automation, water treatment, cooling) and the efficiency of the DC converter are taken into account. The parameters of the model are summarized in Table 3.

Table 3 Parameters of the empirical electrolysis model.

gF-Parameters

I–U-curve r s t1 t2 t3

Fig. 5. Comparison of the modeled I–U-curve with measured data of the HSOLAR 350 kW electrolyzer [27].

5.15667  105 0.25073 0.1009 12.68 849.9

Xm2 V A1 m2 A1 m2 °C A1 m2 °C2

Improvement factor Auxiliary consumption (cooling, control, water treatment) Efficiency DC converter

f11 f12 f21 f22

5000 250 1 0.00025

A2 m4 A2 m4 °C1 – C1

kIF PAux

0.87 0.03 PEL

– kW

gDC

0.98

–

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Fig. 6. Simplified process scheme of the IGCC–EPI concept.

3.2. SNG synthesis

Table 4 Process assumptions for the IGCC plant.

The model of the SNG synthesis is based on the TREMP process shown in Fig. 4. The reactors are modeled as Gibbs reactors (equilibrium reactor given by Aspen Plus). The slight deviation from equilibrium is taken into account by way of a temperature approach of 5 °C, as determined experimentally for the TREMP process in [22]. As stated by [23], the heat of the strong exothermic reactions is used to generate superheated steam at high and intermediate pressures. The temperature levels in the first, second and third reactors are 600 °C, 450 °C and 300 °C respectively, at an operation pressure of the first stage of 30 bar. The recycling rate is determined by the CO content for the inlet stream of the first reactor, which represents a key figure for the reactivity of the gas. Based on experiments using the Lurgi [28] and TREMP [22] processes, the CO concentration is adjusted to 7% through the recycling rate. 3.3. Design of the highly load-flexible IGCC–EPI concept In this load-flexible IGCC–EPI concept, an electrolysis plant is integrated into an IGCC power plant with poly-generation. A simplified process scheme for the IGCC storage power plant concept is presented in Fig. 6. By extracting clean syngas prior to the gas turbine, the power plant can be operated at part load while the capital-intensive gasification plant is still operated at full load. The extracted syngas is then mixed with a pure H2 stream from the electrolysis plant, converted to SNG and fed into or stored in the natural gas network. The integration of the electrolysis plant offers the possibility to achieve negative loads and hence to integrate and store excess power. Additionally, the electrolysis plant enables the adjustment of the optimal gas composition for SNG synthesis without the losses involved in a CO shift. The optimal gas composition can be defined by the ratio of the reactants H2, CO and CO2 given by the gas module M as follows [23]:

M¼

xH2  xCO2 ¼3 xCO þ xCO2

ð3:1Þ

This results in maximum product quality or methane content, respectively, without post-treatment. Even small deviations from the optimal feed gas composition will reduce the SNG quality, which is difficult to control with the conventional method of

Parameter

Unit

Value

Parameter

Unit

Value

1320 19.2 0.895 0.995 1.05

g HP steam turbine g MP steam turbine g LP steam turbine HP steam MP steam

– – – bar bar

0.89 0.93 0.92 170 40

0.985 0.965 1.2 65

LP steam Condenser pressure Pinch point T flue gas to stack

bar bar °C °C

6 0.048 >8 <110

bar

1.2

pressure of the HPcolumn

bar

6

bar MW

33 1.4

Temperature Steam supply

°C kg/s

1450 0.3

Combined cycle power plant TIT (ISO) °C p bar gis gas turbine – gmech gas turbine – pressure outlet bar turbine g Generator – g Motor – Dp control valve bar Net power output MW Air separation unit Pressure of the LPcolumn Gasifier Pressure Heat loss

bypassing the sour shift [23]. Hence adding pure H2 provides a simple, precise and fast way to control the gas composition. To avoid poisoning of the synthesis catalyst, the sulfur content of the syngas must be reduced to less than 0.1 ppm [11]. This is achieved by a zinc oxide bed as well as through the dilution with the sulfur-free H2 stream from the electrolysis plant. In addition to the abovementioned advantages, the following synergies arise:  O2 produced in the electrolysis plant can be stored and used for gasification in times of a high energy demand. Hence the auxiliary demand of the ASU is reduced, resulting in increased net power output.  Mixing H2 produced by excess power with the syngas containing CO and CO2 avoids an additional separation step of CO2 for SNG synthesis.  The heat released by the exothermal methanation process can be integrated into the steam cycle of the combined-cycle power plant. In combination, the aspects mentioned here lead to a highly load-flexible IGCC power plant with a substantial positive and

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negative control range. The modeling of the main components of the IGCC power plant (ASU, gasifier, quench, acid gas wash and combined cycle power plant) has been described previously [29,30]. The major process parameters for the simulation are summarized in Table 4 and the chracterization of the selected hard coal is given in Table 5. As the electrolysis plant is operated in times of low electrical energy prices (or even negative prices), the operating costs for compression are considered to be very low and the oxygen is stored at high pressures (between 36 bar and 100 bar). The SNG is fed into the gas grid at a pressure of 60 bar. For the analysis of the presented concept at various operating conditions, the load restrictions and part-load behavior of the ASU, the gas turbines, the electrolysis plant, and the methanation process must first be identified. For ASUs, Air Liquide has demonstrated that load change rates of at least 5%/min and a part-load operation of at least 50% can be achieved [31]. For gas turbines, load change rates of 15%/min [32] and a minimal part-load operation of 15–25% in the case of a combined cycle with two gas turbines are reported [33]. At part-load operation of the gas turbines, the efficiency loss must also be taken into account, which is done based on the mean value of various published efficiency curves (Fig. 7). The efficiency change of the steam turbines is neglected, because due to the additional steam generation in the methanation stage, the steam turbines are operated at almost con-

Table 5 Characterization of the selected hard coal. Parameter

Unit

Value

C H O N S Cl

wt% wt% wt% wt% wt% wt%

66.52 3.78 5.47 1.56 0.52 0.009

Ash Moisture Volatiles

wt% wt% wt%

14.15 8.0 22.9

Cfix LHV HHV

wt% kJ/kg kJ/kg

54.9 25,174 26,232

Fig. 7. Part load efficiency of the gas turbine [10,45,46].

875

stant conditions. For alkaline electrolyzers, the minimal part-load is limited to 20–25% and load change rates of 50–100%/min [34] are given. The efficiency improvement at part-load operation is taken into consideration by the model itself, as presented above. Dynamic experiments for the methanation process were conducted with the pilot plant ADAM II (SNG production approx. 3500 Nm3/ h) with part-load operation of 23–100% [35]. No specifications were given concerning the maximum load change rate. It is reported in [35] that the system can immediately start up after a shutdown of half an hour. Longer standing times require the system to be heated in order to maintain an ignition temperature of about 300 °C for the methanation catalysts. This implies purging the reactors with hydrogen and external heating of the reactors due to the heat loss. The heat loss of the ADAM I system (SNG production approx. 215 Nm3/h) is given as 14 kW at a reactor temperature of 600 °C [35]. Based on this, a heat demand of 500 kW is estimated for the simulated system to keep the methanation reactors at the ignition temperature of 300 °C. On the basis of the experience from these large-scale plants, five realistic cases were defined for the analysis of the IGCC–EPI concept at various operating conditions (Table 6). In the base case BC the plant is operated like a conventional IGCC power plant with no synthesis gas extraction. However, heat must be extracted from the combined cycle power plant in order to keep the methanation reactors at ignition temperature, which results in a slight efficiency loss. Additionally, a case BC-O2ST is simulated, with part-load ASU operation of 50% and use of the oxygen from the storage. The presented electrolysis cases EC differ in terms of the amount of synthesis gas extraction (20% in EC-20 to 100% in EC-100) and the load of the gas turbines, respectively. 4. Results and discussion 4.1. Verification The verification of the major components of the IGCC–EPI concept has been published previously [30]. Hence, only the electrolysis and the SNG synthesis are verified at this point. The performance of the empirical electrolysis model based on the HYSOLAR electrolyzer (Casale Chemicals) [27] is compared with data from commercial electrolysis modules (Fig. 8). Assuming a conservative improvement factor of 0.87 (at the lower end of the improvement potential stated by the use of activated electrodes [27]), the model has a specific energy consumption of 4.43 kW h/ Nm3 at full load (4000 A/m2). This is within the published range of commercial large-scale electrolysis (e.g. ELT BAMAG: 4.3– 4.6 kW h/Nm3 [36]). The simulation results from the SNG synthesis are compared to data from the ADAM I pilot plant [22]. As shown in Table 7, the model reproduces the measured values with a maximum deviation of 7.1% for the volume flow and 4.1% for the gas composition, except for the CO2 exit concentration in reactor 3. This, however, is also caused by the very low concentration of CO2, and the small absolute error in the CO2 content does not lead to a relevant deviation in the resulting SNG quality.

Table 6 Definition of the investigated operation conditions. Defined cases

Syngas offtake (%)

GT load (%)

ASU load (%)

Description

BC

0

100

100

BC-O2ST EC-X

0 X (20–100)

100 100-X

50 100

Conventional IGCC power plant without CCS and with heat extraction for the methanation reactors BC with part load operation of the ASU and use of the stored O2 Extraction of syngas for SNG-synthesis. Part load operation of the gas turbine and adjustment of the optimal gas composition for the synthesis reaction by H2 produced by electrolysis. Storage of the byproduct O2

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Fig. 8. Comparison of the specific energy consumption derived from published I–Ucurves [14,47–49] and the electrolysis model based on the HYSOLAR 350 kW electrolyzer with an improvement factor of 0.87.

Table 7 Deviation in % of the results of the SNG-synthesis model from experimental data of the pilot plant ADAM I [22]. Deviation in (%)

Reactor 1 Reactor 2 Reactor 3

Gas composition

Volume flow V_

CO2

CO

H2

CH4

H2O

0.9 1.5 48.2

4.1 – –

0.8 2.3 0.9

0.2 0.1 0.4

0.5 0.3 0.8

7.1 1.2 4.1

4.2. Operating pressure electrolysis In the following, the optimal operating pressure of the electrolyzer for integration into the IGCC–EPI concept is determined, taking into account the energy consumption for compression of the product gases. In Fig. 9, the energy consumption of the electrolysis plant (EC-80), including auxiliary consumption of the water pump (g = 83%), O2 and H2 compression (gis = 85%, gmech = 95%) is shown at various operating pressure levels and operation periods. For the simulation, discharge pressures of 75 and 31.5 bar (equal to the syngas pressure) are assumed for oxygen and hydrogen, respectively. In continuous operation, purge gas losses can be neglected, which reduces the energy consumption of the pressurized electrolysis (31.5 bar) by 1.7% compared to ambient pressure operation. However, if the electrolyzer is not operated continuously, purge gas losses become significant and lead to losses at higher pressures. Therefore the electrolyzer pressure is set to 5 bar, a pressure level at which energy consumption is still acceptable but a compression stage for O2 and H2 can be saved (see Fig. 9). This can change in the future if electrolyzers are optimized for dynamic operation, reducing the need for purging as well as the purge gas volume.

Fig. 9. Energy consumption of the electrolysis plant (EC-80) dependent on the pressure and the mean operating time (including water pump, O2- and H2compression).

Fig. 10. Comparison of the net power, electrolyzer power, internal energy consumption and power generation of the steam and gas turbines of defined operation cases.

4.3. Load flexibility of the IGCC–EPI concept To demonstrate the superior load flexibility of the proposed IGCC–EPI concept, various operation cases were simulated and compared to the base case (BC) (Fig. 10). During normal operation, all of the syngas is used in the combined cycle, while some heat is extracted to maintain the ignition temperature of the methanation reactors. In this way the plant achieves a net power output of 64.7 MW. The heat extraction leads to an efficiency loss of 0.2% points. If stored oxygen is available, the power output can be improved by part-load operation of the ASU. At part-load operation of 50% (BC-O2ST), internal energy consumption is reduced by 31.3%, which improves the net power output by 3.9% (to 67.3 MW). In the case of low electrical energy demand or even excess power, syngas is extracted and converted to SNG. At a syngas extraction rate of 20% (EC-20), the net power of the IGCC–EPI plant decreases to 6.2 MW. Extraction rates of 50% (EC-50) and 100% (EC100) result in a negative net power balance of 85.1 MW and 253.4 MW, respectively. Hence external power is integrated into the EPI plant and stored chemically as SNG. The negative net power is caused by the energy consumption of the electrolysis plant, which is 274 MW at full load (EC-100). Additionally, the energy consumption for compressing H2, O2 and SNG increases at higher extraction rates, resulting in an internal energy consumption by the storage section of 1.9 MW (EC-20) and 9.7 MW (EC-100). In contrast, the internal energy consumption of the power plant slightly decreases (8.0 MW in BC to 6.5 MW in EC-100) due to the lower N2 demand for dilution of the fuel gas, therefore requiring lower power consumption for compression. Consequently, the proposed IGCC–EPI concept is able to reach a positive control range of +67 MW (BC-O2ST) and a substantial negative control range of up to 253 MW (EC-100). The power output of the gas turbines is reduced proportionally to the SNG production due to the extraction of syngas. The load of the steam turbines increases with SNG production because of the integration of steam generated in the methanation process. In EC-100, the power output of the steam turbines is 36.3 MW, which is 24% above the base case BC (29.2 MW). Fig. 11 shows the net power of the plant as well as the SNG and O2 production rate dependent on the syngas extraction. Above a syngas extraction rate of 22.2%, negative net power occurs. At a syngas extraction rate of 100% (EC-100), 29,833 Nm3/h O2 and 23,862 Nm3/h SNG are produced. In all cases, the SNG fulfills the quality requirements for direct injection into the grid (methane content of 94%, HHV = 10.5 kW h/Nm3). The O2 production of the electrolysis modules at full load (EC-100) corresponds to about six times the O2 demand when the ASU is operated at a part load of 50% (BC-O2ST). The lines between a syngas extraction of 80%

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Fig. 11. Dependency of the net power and production rate of SNG and O2 from the syngas extraction.

and 100% are dotted due to the assumption that the gas turbines cannot be operated at a part load below 20%. Therefore, above 80% extraction, the total syngas must be extracted and used for SNG production. The most important simulation results for the defined operation cases are listed in Table 8. 4.4. Plant efficiency of the IGCC–EPI concept The impact of part-load operation as well as of the synergy effects on plant efficiency are analyzed in the following. Due to the different forms of energy involved, it is difficult to define an energetic efficiency. As a result, the exergetic efficiency has been calculated for the conversion of coal and excess energy into electricity, SNG and oxygen (reference environment according to [37] with T1 = 298.15 K and p1 = 0.91771 bar). The overall exergetic efficiency is defined as follows:

fov erall ¼

E_ SNG þ E_ O2 þ Pnet ðif Pnet > 0Þ _Ecoal þ E_ CH  P net ðif Pnet < 0Þ 4

ð4:1Þ

where E_ SNG , E_ O2 , E_ coal and E_ CH4 are the exergy flows of SNG, oxygen produced by the electrolyzer, coal and methane used for drying the coal. The net power is considered on the benefit side in the case of positive net power, whereas it is considered on the effort side in the case of negative net power. By taking into account the reconversion of the storage media SNG and O2 into electrical energy, an overall energetic efficiency can also be defined:

gov erall!Electricity ¼

_ O2  EASU þ W O2 ;T þ W O2 ;C þ Pnet ðif Pnet > 0Þ _ SNG  LHVSNG  gcc þ m m _ coal  LHVcoal þ m _ CH4  LHVCH4  P net ðif P net < 0Þ m ð4:2Þ

The conversion of SNG into electricity is considered by way of the lower heating value LHVSNG and a combined cycle efficiency gcc of 60%. The electricity equivalent of the stored oxygen is calculated using the specific energy consumption of the ASU for oxygen production (EASU = 0.273 kW h/kg [29]). Additionally, the pressure

Fig. 12. Dependency of the plant efficiency from the syngas extraction.

energy of the oxygen is taken into account – on the one hand by the work W O2 ;C that would be necessary to compress the oxygen from the discharge pressure of the ASU to the gasifier pressure, and on the other hand by the pressure energy W O2 ;T that can be converted to electrical energy by decompressing the gas from the storage pressure to the gasifier pressure in a turbine (gs,T = 0.91). In summary, the overall energetic efficiency goverall?Electricity represents the conversion efficiency of coal and excess energy to SNG and oxygen and back to electrical energy. As seen in Fig. 12, the electrolyzer shows the expected part-load behavior, with decreasing efficiency at full load. In contrast, the overall energetic and exergetic efficiency decreases at part-load operation of the electrolyzer with a minimum of goverall?Electricity = 26.2% foverall = 38.9%) at a syngas extraction rate of 22.2%. This corresponds to the syngas extraction with Pnet = 0 (Fig. 11). The maximum efficiency in the case of energy storage is reached at 100% extraction with goverall?Electricity = 40.1% (foverall = 60.6%). This behavior can be explained by the use of the electricity generated in the combined cycle for electrolysis, in the case of low extraction of synthesis gas (no net power or only a small negative net power). This represents the energetically unfavorable way of converting coal into hydrogen via gasification, electricity generation and electrolysis. At a syngas extraction rate of 22.2%, the electrolysis plant is completely fed by electricity generated in the combined-cycle power plant (Pnet = 0). In contrast, at a syngas extraction rate of 100% (EC100), only 7.4% of the electricity for the electrolyzer is provided by the combined cycle and 92.6% is provided by externally generated excess power. As a result, for a maximum integration of excess power and storage efficiency, the energy consumption of the electrolysis system should be as high as possible compared to the power generation of the combined cycle plant. This is mainly dependent on the H2 demand, which results from the difference between the gas composition of the synthesis gas and the optimum gas composition for the subsequent synthesis.

Table 8 Overview of simulation results for defined operation cases. BC

BC-O2ST

EC-20

EC-50

EC-80

EC-100

Syngas extraction (%) ASU load (%)

0 100

0 50

20 100

50 100

80 100

100 100

GT power (MW) ST power (MW) Electrolysis plant (MW) Internal energy consumption (MW) Net power (MW)

43.5 29.2 – 8.0 64.7

43.5 29.2 – 5.5 67.3

32.0 32.4 48.6 9.5 6.2

18.2 35.0 126.3 11.9 85.1

4.7 36.2 212.4 14.3 185.7

0 36.3 273.6 16.2 253.4

Electrolysis efficiency (HHV) (%) Overall exergetic efficiency (%) Overall energetic efficiency (%) (including reconversion of storage medias to electricity)

– 47.3 50.2

– 48.8 52.3

91.4 39.1 28.6

88.0 53.3 35.9

83.7 58.7 39.1

81.2 60.6 40.1

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In the next step, further variations of the proposed highly loadflexible IGCC–EPI plant will be investigated, including alternative synthesis plants, high-temperature electrolysis as well as oxy-fuel and fuel cell concepts. Moreover, an economic analysis and optimization of the presented concept is planned. Acknowledgments

Fig. 13. Impact of the heat and oxygen integration on the overall efficiency goverall?Electricity in the case EC-100.

This work is related to the Project HotVeGas, which is supported by the BMWi and industrial partners (Air Liquide, EnBW, RWE, Siemens and Vattenfall) under Contract Number 0327773E. The authors would like to thank all of the partners for their valuable input and discussions. Thanks also goes to the TUM Graduate School. References

The following analyzes the impact of the synergies on overall efficiency. Therefore the overall efficiency at full storage operation with 100% extraction of synthesis gas (EC-100) is compared to a stand-alone coal methanation or power-to-SNG plant, respectively. Based on a literature review by [38], an overall efficiency of 59–65% from coal to SNG can be identified, which results in a coal-to-electricity efficiency of 35–39% (with gcc = 60%). The overall efficiency for the power-to-SNG technology is planned to be in the range of 60% [39], which results in an overall efficiency of 34% from power to SNG and back to power (including compression of the SNG to 60 bar and taking into account the energy consumption for the CO2 sequestration). Therefore the overall efficiency of the IGCC–EPI plant of 40.1% at full storage operation indicates a significant efficiency advantage by combining these two processes. Fig. 13 shows the impact of integrating the heat of the SNG synthesis and the oxygen of the electrolysis plant. The use of the oxygen and the heat from the methanation corresponds to overall efficiency improvements of 4.1% points and 2.9% points, respectively. 5. Conclusion This work presents and analyzes a highly load-flexible IGCC–EPI (Excess Power Integration) power plant for integrating excess power from renewable energy sources and inflexible conventional power plants. The decentralized power plant incorporates both a synthesis and an electrolysis plant. In conventional operations, the proposed concept achieves a net power output of 64.7 MW. Through part-load operation of the ASU (50%) and integration of stored oxygen in times of high electricity demand, this can be improved by 3.9%, to 67.3 MW. In times of low electricity demand or even excess power, the syngas is extracted prior to the power plant and converted to SNG. The gas composition is adjusted using hydrogen provided by the electrolysis plant, which has a maximum energy consumption of 274 MW at 100% syngas extraction. Negative net power is achieved above a syngas extraction rate of 22.2%, with Pnet = 253 MW at 100% syngas extraction. The integration of the steam from the methane synthesis section and the oxygen from the electrolysis in the IGCC power plant results in an overall efficiency of 40.1%, at full storage operations, from coal and excess power to SNG and back to electricity. This represents the maximum storage efficiency of the plant. The minimum overall efficiency of 26.2% is given at an extraction rate of 22.2%, which corresponds to a net power of Pnet = 0. This can be explained by the fact that the electrical power generated by the combined cycle is used internally by the electrolysis plant. To avoid the conversion-related losses in the IGCC and to maximize the integration of excess power, the ratio of energy consumption in the electrolysis plant to the power generation of the combined cycle should be as high as possible.

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