Renewable substitute natural gas synthesis VGB PowerTech 12 l 2018
Renewable substitute natural gas synthesis
Author
Kurzfassung
Herstellung von regenerativ-synthetischem Erdgas in Energieerzeugungs- und Vergasungsanlagen als Konzept zur Energiespeicherung
Die Produktion von synthetischem Erdgas, auch bekannt als SNG, fördert die umfängliche Nut-zung erneuerbarer Energiequellen (EE) im Strom-, Wärme- und Transportsektor. In der vorliegenden Arbeit wird die SNG-Produktion durch die Modellierung und den Vergleich von 3 verschiedenen Fällen untersucht. Das Hauptziel ist die Herstellung von SNG mittels Strom aus erneuerbaren Quellen und die Möglichkeit der Energiespeicherung durch die Integration von Wasserelektrolyseuren in Kraftwerken und Ver-gasungsanlagen. Die Abregelung der EE- Stromeinspeisung führt zu Energieverlusten, die in wertvolle Energieträger wie SNG umge-wandelt werden könnten. Gleichzeitig werden direkte CO2- Emissionen während des SNG-Produktionsprozesses verwendet oder redu-ziert. In kombinierten Vergasungs- und Elektro-lyseanlage werden existierende Technologien, wie die kryogene Luftzerlegung, das Wassergas-Shift-Katalysatorsystem und die Sauergasab-scheidetechnologie, vollständig ersetzt oder minimiert. Die Effizienz basierend auf der che-mischen Energie für die drei Prozesse variiert zwischen 51 % und 63 % und ist deutlich beein-flusst von der Effizienz des Wasserelektroly-seurs. Die optimale Wärmeintegration führt zu höheren Gesamtwirkungsgraden. Die SNG- Er-zeugungskosten können, abhängig von Strom- und Biomasse- Preisen, um ein vielfaches höher sein als die Kosten für fossiles Erdgas. l
Dr. Efthymia Ioanna KoytsoumpaMitsubishi Hitachi Power Systems Europe GmbH Duisburg, GermanyandNational Technical University of Athens Laboratory of Steam Boilers and Thermal Plants Athens, Greece
Renewable substitute natural gas synthesis integrated in power and gasification plants for energy storage Efthymia Ioanna Koytsoumpa
Introduction
The impacts of increasing renewable ener-gy sources (RES) on grid operations have already shown several amounts of cur-tailed energy. In California, CAISO reports in [1] 187 and 308 curtailed RES GWh in 2015 and 2016 and an increase of 147 % during the first quarter of 2017, while dur-ing certain periods during the year, solar curtailment of 20 to 30 % is not unusual. In Germany, curtailment energy in 2017 reached a total of 5,518 GWh, representing an increase of 47 % compared to 2016 (3,743 GWh) [2]. In 2016, 227 GWh of wind energy were dispatched among the 7,620 GWh total wind energy produced in 2016 in Ireland and Northern Ireland, rep-resenting 2.9 % of the total available wind energy in the same year [3]. As Europe tries to maintain curtailment rates under 5 %, China on the other hand is the most profound example of RES curtailment reaching a ratio of around 15 % in 2016, meaning around 50,000 GWh of wind pow-er were wasted. In certain provinces the
ratio reached over 20 %, the same year [4], while in 2017 wind power curtailment vol-ume fell by 7.8 billion kWh compared with that in 2016 according to the National En-ergy Administration (NEA) [5].In 2016, the share of RES in EU28 for elec-tricity reached 29.6 %, while in gross final energy consumption a 17 % was achieved [6]. Moving towards an energy strategy for 2030 with a 27 % of RES in final consump-tion and opting for the targets of Ener-giewende by 2050, several TWh energy loss per year are to be expected with in-creasing RES capacity even with reduced curtailment ratios. Valuing curtailment is a very important aspect of energy transition not only in terms of energy and environ-mental aspects but also reducing financial losses in a highly subsidized sector. Espe-cially, baring in mind that the share of en-ergy products in total EU imports is in-creasing – Germany is the largest energy importer among EU members-, storing and converting the curtailed energy could be a key issue in the new energy trajectories. Gas imports have the second largest share
Utilisation ofCO2 Emissions
Water Electrolyserwith surplus RES
electricity
Reduction ofCO2 EmissionsReplacementof ASU, WGS
& AGR Existing Natural Gas Grid
SNGProduction
Power Plants
Gasification Plants
Biogas Plants
SectorCoupling
mobility Chemicals Process Industry private customers
RES: Renewable Energy Sources, SNG: Substitute Natural Gas, ASU: Air Separation Unit, WGS: Water Gas Shift, AGR: Acid Gas Removal
other
H2
CO2
CO2
CO
H2
H2
Fig. 1. SNG Production in power and gasification plants.
VGB PowerTech 12 l 2018 Renewable substitute natural gas synthesis
after oil and the production of Substitute Natural Gas (SNG) could take advantage of the well – established natural gas grid. As-suming that SNG production can be achieved with 51 % and 45 % of the cur-tailed energy in Germany in 2017 can be utilised, a potential of 3 SNG plants with 50 MWth production capacity and 96 % yearly availability could be achieved today. In the present work, the production of SNG in combination with water electrolysis for energy storage is investigated for integra-tion in power plants and simultaneous Car-bon Capture and Utilisation (CCU) [7, 8] and in gasification plants for reduction of CO2 emissions and enhancement of the production. The main advantages and opti-mum efficiencies in each case are present-ed, while the levelized cost of production today is investigated. F i g u r e 1 presents the overall scheme of the power to fuel and combined gasification and power to fuel processes.
Modelling of Power to SNG technology integrated in power and gasification plants
Case 1: Integration in a lignite fired power plantThe overall block flow scheme for the Pow-er to SNG synthesis is presented in F i g -u r e 2 , where the numbering of different mass and energy streams and technology blocks is depicted. In thermal power gen-eration, including combustion of fossil fu-els, biomass, municipal waste and other waste to energy plants, carbon dioxide is available in large quantities and can be captured after the combustion process (Post Combustion Capture- Block 2), which has been demonstrated at full commercial scale [7]. Depending on the electrolyser capacity, a partial stream of the flue gases is treated in the PCC process. The electrolyser technology (Block 1) can be categorized in alkaline (AEL), polymer exchange membranes (PEM), and solid ox-ide fuel electrolysers (SOEC) as well as chloro-alkali electrolysers for chlor pro-duction. Water electrolysis is the electro-chemical process, where water is split to its basic components, hydrogen and oxygen electric power. The AEL has reached com-mercial scale and has found applications in MW scale. For the electrolyser technology, only AEL was considered but no detailed modelling was performed. A total electri-cal efficiency including all electrical con-sumptions of peripheries, cell and trans-formers as well as electric to heat losses was set at 4.3 kWh/Nm3 defined at 25 °C. According to [9, 10]. the efficiency varies from 4.3 to 8.2 kWh/Nm3. For the integration of power to fuel in ther-mal power plants, a worst case with lignite is investigated considering today’s base load operation. Except from the lower effi-
ciencies of lignite fired power plants (PP) compared to hard coal fired power plants, the examined lignite case (Block 5) uses low quality Greek lignite. Ta b l e 1 pre-sents its composition and its Lower Heating Value (LHV). Air with a mass flow of 455 kg/s is preheated at 270 °C, while the mass flow of lignite inserted in the boiler was set at 169.72 kg/s. The lignite plant has a gross efficiency of 39.7 %, a net efficiency in the steam cycle of 38.78 % and an overall net efficiency of 37 % including all plant
auxiliaries. The respective power produc-tion is 366.5, 358 and net 341.6 MWe. The steam cycle was simulated with a super-heated steam at 536 °C and 190 bar, while the steam from the high pressure turbine was fed in the reheater at the pressure of 34.93 bar. Low pressure low temperature preheating is performed at 10.11 bar. The total steam water flow was equal to 275 kg/s. As depicted in F i g u r e 3 , a steam bleed after the medium pressure tur-bine is used for covering the reboiler needs
Thermal Energy1.0 2.0 3.0 4.0
Electricity2.1 3.1 4.1
1.2 H21.3 Off-gas1.4 water
1.1
5.4 fuel
5.3 agent5.1 5.0
5.2
2.6 2.5
1. HydrogenProduktion
Power plantFlue gascleaning
2. CO2capture
3. Com-pression
4. Fuelsynthesis
2.2 3.2CO2
2.4 solvent
2.3 condensates
5.5 flue gas
3.3 condensates
4.3condensates
4.2 SNG
X.0 Thermal EnergyX.1 ElectricityX.2 Main Process StreamX.X Process Streams
Fig. 2. Block flow diagram for power to SNG – Case 1: Integrated in power plants.
Tab. 1. Power to SNG plant – Main Process Streams and their Composition – Case 1.
No Stream- Power to SNG
m (kg/s)
P (bar)
T (oC)
1.2 Hydrogen 0.835 30 30
1.3 Off gas (O2) 6.562 30 30
1.4 Water 7.397
2.2 CO2 rich gas 4.608 1.18 38
2.3 Condesates 0
2.4 Solvent 119.96 2 38
2.5 Off gas 19.255 1.09 38
2.6 Treated gas 23.897 1.05 38
3.2 Compressed syngas 5.335 30 30
3.3 Condensates 0.108 1.01 35
4.2 SNG 1.642 81 25.5
4.3 Condesates 3.693 1.01 35
5.5 Flue gas 530.288 1.05
5.2 Flue gas (ash free) 599.91
Mol % composition/Flue gas composition on wet basis
H2 N2 O2 H2O CO2 CO CH4 other
5.2 57.956 3.298 27.477 11.064 ppm 0.2
2.2 0.025 0.003 0.282 99.686 0.004
Mol % composition – Power to SNG plant – Composition of Feed and Product Streams
H2 N2 O2 H2O CO2 CO CH4 other
1.2 99.87 0.13
3.2 79.91 0.15 19.93 0.01
4.2 0.91 0.09 98.99 0.01
Ultimate Analysis of Lignite on weight dry basis
( % w/w) C H N S O Cl
Lignite 39.13 3.15 6.54 0.96 18.46 0.02
Proximate Analysis of Lignite on weight dry basis and Heating Values
Renewable substitute natural gas synthesis VGB PowerTech 12 l 2018
of the subsequent PCC unit. The extracted mass was set equal to 5.6 kg/s at 5.1 bar and is re-inserted in the steam cycle before the feed-tank. A total capture ratio equal to 4.04 % of the power s plant CO2 emissions is achieved.In the post combustion capture, gas pre-treatment is required due to the fact that sulfur and nitrogen oxides, particles and other metal traces exist in the flue gas. Commonly a NaOH scrubber is inserted be-fore the PPC. Specifications for 99 % re-moval of these species have been set for the flue gas cleaning treatment. The clean flue gas is conditioned to 2.2 bar and 38 °C in order to overcome the pressure drop of the flue gas inside the absorber but also to have a slightly pressurised operation. The tem-perature of the flue gas and Methyldietha-nolamine (MDEA) solvent is set at 38 °C. The CO2 lean stream after leaving the ab-sorber is cooled down and separation of the entrained water and solvent content takes place, which are sent back at liquid phase to the storage tank. The rich solvent passes through several conditioning steps involving throttling, cooling, condensing and reheating before it is inserted in the desorber. In the desorber, the thermal sep-aration of CO2 and the solvent takes place via providing heat in the reboiler. The lean solvent after cooling in the cross flow heat exchanger is also led to the storage tank. The captured CO2 from the PCC unit (Block 2) is compressed in multi compres-sor stages with intermediate cooling up to the pressure of 30 bar in the compression and mixing unit (Block 3), where it is final-ly mixed with the produced hydrogen from
the electrolyser unit. The SNG synthesis model (Block 4) has been presented in [11] for the equilibrium and kinetic calcula-tions. According to the kinetic model of CO2
methanation, it was shown that a conver-sion of 96 % of CO2 can be achieved with bulk methanation reactors and recycling, intermediate condensation and trim meth-anation. In this work, the equilibrium mod-el is used, implementing a two stage syn-thesis as described in [11, 12]. Syngas in a stoichiometric ratio equal to 4 is fed at 30 bar and at 300 °C in a cross flow preheater at 300 °C before entering the first low pres-sure adiabatic bulk reactor, operating at 28.9 bar and up to 500 °C. The product be-fore fed to the trim reactor operated at 77.9 bar and 300 °C, cools the reactants, passes through condensation and water separa-tion, recompression to 80 bar and reheating to 280 °C in a second cross flow heat ex-changer. Finally, the end product after the trim reactor is conditioned for water remov-al and lead to the last compression unit, which serves to overcome any pressure losses and is fed to the grid. The mass flow, conditions and composition of main streams are presented in Ta b l e 1 . As the methana-tion process is an exothermic process, a high amount of high temperature heat is availa-ble as depicted in F i g u r e 4 . This heat can be optimally integrated in the power plant. The overall electricity demand of the power to SNG plant is equal to 158.81 MWe, result-ing in a Cold Fuel Efficiency (CFE) of 51.59 % defined as the energy content of SNG based on LHV divided by the total elec-tricity demands as shown in Ta b l e 2 .
Steam to Power toSNG
G
Hot water from PtSNG
CondesateFrom reboiler
Fig. 3. Configuration of heat utilisation for integration of SNG in power plant – Case 1.
Duty in MW
Tem
pera
ture
in o C
520
470
420
370
320
270
220
170
120
70
200 10 20 30 40 50 60
hot composite curve
cold composite without reboiler
cold composite with reboiler
cold composite without reboiler with HP heating
cold composite without reboiler with HP+LP heating
DTmin = 20 K ,Thot = 210 oCTcold =190 oC
Fig. 4. T-Q Diagram – Heat integration of power to SNG in power plants – Case 1.
Tab. 2. Power to SNG plant – Main Energy flows – Case 1.
VGB PowerTech 12 l 2018 Renewable substitute natural gas synthesis
In the case of stand-alone power to SNG ap-plications, no external source is required. However, when the technology is integrat-ed in a power plant, the high temperature heat could be used to optimally in high pressure heating at the temperature range 350 to 220 °C, the reboiler needs are can be covered with steam at the end of the inter-mediate turbine at 5.11 bar and further heat utilisation at lower temperatures at the temperature range 190 to 105 °C could improve the overall integrated efficiency. The steam for the reboiler is provided at the end of the intermediate turbine at 5.11 bar. As shown in Ta b l e 2 , extracting steam from the power plant leads to an en-ergy penalty of 2.537 MWe, which includ-ing the energy penalty in PP would result in 161.35 MWe. As energy penalty in the refer-ence plant is defined here the difference to steam cycle efficiency in normal operation and with integration of the power to fuel plant including the electricity required for circulating the reboiler s steam. With the heat integration at high pressure preheat-ers, the steam bleed from the intermediate turbine is reduced and thus more electrici-ty is produced. The optimum results for the case of power to SNG and its integration to a power plant show a total Energy Conver-sion Efficiency (ECE) increase from 50.78 % to 52.66 % based on the fact that the surplus electricity is not directed to the grid, but to the power to SNG plant.
Case 2 and Case 3: Integration in an oxygen steam biomass gasification plantSolid fuel gasification can provide a hydro-gen rich syngas and the necessary carbon for subsequent SNG synthesis. Its combina-tion with water electrolysis enhances the overall fuel production and enabling sea-sonal energy storage. In addition, it results in reduction of CO2 emissions compared to the conventional gasification pathways as more carbon is used for the fuel produc-tion. The overall block flow scheme for the Gasification and Power to SNG synthesis is presented in F i g u r e 5 , where the num-bering of different mass and energy streams and technology blocks is depicted. Solid fuel – in the studied cases sunflower – is inserted in a steam oxygen gasifier, de-noted as Block 5. The highly valuable syn-thetic gas produced in the gasifier passes through high temperature (HT) filtration and cooling system. As presented in Ta -b l e 3 , two optimum cases are presented here after investigation of different pro-cesses published in [12]. Case 2 refers to the case, where the electrolysers are cover-ing only the oxygen demand for the gasifi-cation process and Case 3, where oversized electrolysers are implemented resulting in an oxygen surplus, while Water Gas Shift (WGS) and Acid Gas Removal (AGR) sys-tems are not required. Thus, Block 7 as well as Block 2 are not considered in Case 3.
Steam/oxygen gasification for small scale applications is modelled with sunflower as fuel in respective operating pressures of 5 bar and 800 °C and with a carbon conver-sion of 99 %. The fuel analysis for the sun-flower as well as the composition of the syngas produced is presented in Ta b l e 3 . For the oxygen/steam gasification, the oxy-gen demand is covered by the electrolyser technology, while process steam is pro-duced inside the overall process. The CFE defined as the energy content of syngas produced divided by the energy content of sunflower both in LHV is equal to 80.86 %. The electricity demand denoted for this block in Ta b l e 4 is only limited to lock hopper systems, screw feeders and other peripheries. At HT Filtration particles and traces of metal are removed and syngas is cooled down before entering the HT heavy tar removal system at 400 °C. No additional scavenging for Benzene, Toluene, Xylene (BTX) species was considered as these spe-cies can be converted in the methanation process [13]. Organic sulphur removal as well as hydrogen sulphide removal is per-formed with activated carbon. In Case 2, where syngas is fed to the WGS unit, hy-drolysis of carbonyl sulphide also takes place as sour WGS unit was considered. Activated carbon is used instead of other hot desulphurisation processes such as ZnO operating at 230 °C and subsequently syngas is cooled either to the required tem-perature of the acid gas removal system at 40 °C in Case 2 and down to 120 °C in Case 3. MDEA is investigated as acid gas remov-al (AGR) process for the Case 2 with elec-trolysers sized according to the oxygen de-mand. In Case 2, the amount of hydrogen sulfide is drastically reduced reaching 99 % removal in AGR. However, scavenging with 99 % removal of all sulphur, chloro and ni-trogen species was considered in both cas-es before mixing with the produced hydro-gen as these species can poison the subse-quent catalysts [13].
For SNG synthesis process, the above de-scribed equilibrium model with the same temperature conditions for bulk and trim methanation has been used. Syngas con-taining CO, CO2 and H2 in a stoichiometric number equal to 3.01 is inserted in the adi-abatic bulk methanation reactor at 4.4 bar for Case 2 and 4.6 bar for Case 3. Main compression takes place after the bulk methanation and before the trim reactor, while the last compression for feeding the SNG to the grid is also implemented here. The overall available thermal energy and electricity demand for the two cases is pre-sented in Ta b l e 4 . Cold SNG efficiency is defined here as the chemical energy output of the SNG divided by the energy input in terms of LHV of the gasified fuel and the total electricity input and is equal to 63.43 % for Case 2 and 57.67 % for Case 3.
The gasification process determines the subsequent fuel production, as a slight de-viation of the process parameters and feed-stocks influences the gas cleaning, water gas shift, CO2 capture process and the final synthesis. For the SNG synthesis, the high-er methane and ethane content enhanced the SNG production and these species and also a small amount of light tars can be op-timally reformed in the high temperature bulk reactor of the methanation process, increasing the overall conversion. Fuels with higher nitrogen content, introduce a N2 inert volume in the overall process, which is influencing the quality of the product. The effect of nitrogen content on the SNG quality resulted in an additional 1.5 % mol based fraction in Case 2 than in Case 3. Nitrogen may also play a significant role as it can be used in the overall plant as an inert gas in the solid fuel feeding system or for purging purposes.
The requirements for conversion were set according to the stoichiometric ratio after a 90 % CO2 capture in the subsequent unit and after the addition of hydrogen surplus
Thermal Energy
Electricity
1.4 water1.1
8.08.1
7.07.1
6.06.1
5.05.1
1. HydrogenProduction
1.3 Oxygen
1.0 2.0
2.1
1.2H2
3.0
3.1
4.0
4.1
3.2 4. Fuelsynthesis
4.2 SNG
4.3condesates3.3 condesates8.3
condesates
7.3 steam
6.3 solid particles
5.4 fuel5.3 agent
Thermo-chemical plant
5.2 syngas
6. Filtration/Conditioning
6.2 syngas
7.2 syngas
7. WGS
8.2 syngas
8. Con-ditioning
2. Acid GasRemoval
2.3 solvent2.4 CO2
2.2 3. Compression/Conditioning
X.0 Thermal EnergyX.1 ElectricityX.2 Main Process StreamX.X Process StreamsGrey Coloured = Optional
Fig. 5. Block flow diagram for combined electrolyser and gasification to SNG cases [12].
Renewable substitute natural gas synthesis VGB PowerTech 12 l 2018
from the electrolyser. It has to be men-tioned that the WGS process treated only 33.2 % of the syngas produced. Compared to the conventional gasification to fuel pro-cesses, the WGS process had less require-ments both in terms of reactor volume, steam and catalyst as the added hydrogen from the electrolysis has fulfilled the down-stream requirements. For Case 3 the WGS and subsequent AGR unit were not re-quired as the mixture of syngas and hydro-gen fulfilled the stoichiometric ratio. How-ever, the different cases presented differ-
ences between the H2/CO and H2/CO2 ratio. Carbon monoxide enhances the cata-lytic conversion to SNG but optimum ratios are dependent on the catalyst [11]. Water gas shift has a significant role on the overall dimensioning of the system according to the intended operation of the system. Min-imising the electricity import and simulta-neously covering the oxygen demand via electrolysers (substitution of ASU) leads to the investigated Case 2, where all three systems (AEL, WGS and AGR) are required, which is more capital intensive.
The combination of gasification and power to SNG technology provides a high amount of sensible heat, which after heat integra-tion can be used for steam, hot water or even used in a steam cycle for additional electricity production in larger SNG plants. The amount of heat that can be used by heat consumers was equal to 14.82 % of SNG produced in case 2 and 27.47 % in case 3, where the production of SNG equaled to 17.59 MWth and 32.12 MWth for the two cases respectively. Thus, the ener-gy conversion efficiency is equal to 72.83 % for Case 2 and 73.51 % for Case 3 [12].
Sensitivity analysis of considered CasesA sensitivity analysis is performed for the parameters that influence the cold gas ef-ficiency (CFE) and total energy conversion efficiency (ECE) of the power to SNG (Case 1) and gasification and power to SNG (Case 2 and Case 3). It is noted that the chemical energy input both in terms of hydrogen and syngas remains stable in the following analysis, while variations in the syngas composition for Case 2 and Case 3 are not considered. F i g u r e 6 presents the results of the sensitivity analysis ac-cording to individual cases of a decrease or increase of the electricity and heat duties. As it can be seen, the electrolyser technol-ogy plays the most important role in the overall efficiency. An increase of the electrolyser’s need of 7.5 % would result in a cold fuel efficiency of power to SNG decrease from 51.59 % to 48.07 %. This means that from 4.3 kWh/Nm3 to 4.6 kWh/Nm3, a total decrease in the cold fuel efficiency of 3.52 % is to be ex-pected. On the other hand, a decrease of the electrolyser’s need of 7.5 % would result in a cold fuel efficiency of power to SNG in-crease from 51.59 % to 55.67 %, meaning that from 4.3 kWh/Nm3 to 3.98 kWh/Nm3, a total increase in the cold fuel efficiency of 4.08 % is to be expected. The compression work and the reboiler duty do not have a significant impact on the efficiency as if an increase or decrease of 30 % from the refer-ence value could bring an efficiency/de-crease of the cold fuel efficiency not more than 0.5 %. The impact of the reboiler duty is here depicted as electrical losses of the power plant and it is significantly low. This is due to the small total amount of capture compared to full post combustion cases of 90 % CO2 capture and to the fact that ad-ditional heat is integrated to the steam cy-cle, meaning that in power to SNG cases stand-alone plants without optimum inte-gration in the relevant temperature level of the steam cycle and the additional costs and complexicity can be realised.
An increase of the electrolyser’s need of 7 % would result in a cold fuel efficiency of gas-ification and power to SNG decrease from 57.67 % to 55.25 % in case 3 and from 63.43 % to 62.27 % in case 2. This means that from 4.3 kWh/Nm3 to 4.6 kWh/Nm3, a
Tab. 3. Combined Gasification and Power to SNG plant – Main Process Streams and their Composition – Case 2 and Case 3 [12]
VGB PowerTech 12 l 2018 Renewable substitute natural gas synthesis
total decrease in the cold fuel efficiency of 2.42 % and 1.16 % is to be expected for case 3 and 2 respectively. On the other hand, a decrease of the electrolyser’s need of 7 % would result in a cold fuel efficiency of pow-er to SNG increase from 57.67 % to 60.30 % for case 3 and from 63.43 % to 64.63 % for case 2. Thus, an electrolyser efficiency in-crease from 4.3 kWh/Nm3 to 4 kWh/Nm3, a total increase in the cold fuel efficiency of 2.63 % for case 3 and of 1.2 % for case 2 is to be expected. As expected, the case with oversized electrolysers is more dependent on the electrolyser’s efficiency. In both cas-es, the compression work, the electricity needs in the gasification unit and in the capture unit for case 2 do not have a signifi-cant impact on the efficiency as if an in-crease or decrease of 30 % from the total reference value could bring an efficiency/decrease of the cold fuel efficiency not more than 0.5 %. In regard to the heating de-mands, it is shown that there is a high amount of heat available and thus an in-crease of the heating demands of up to 30 % could be covered inside the process with the penalty of less steam provision to heat consumers. It is mentioned here that the variation of process steam has a meaning only for the water gas shift reaction as a change in the process steam feed in the gasification would have an effect on the chemical energy and also on the sensible heat of syngas.
Levelized cost of energy for a 50 MWth SNG synthesis plant
For the comparison of the different pro-cesses studied, the techno-economic analy-sis is based on the same fuel production for 50 MWth SNG and on a time availability of 96 %. It is noted here that although natural gas (NG) is traded according to its higher heating value, the analysis and prices con-
sidered below are based on the lower heat-ing value of the fuel. The input and output energy streams as well as the direct CO2 emissions during the production are de-noted in Ta b l e 5 . As it can be seen, the power to SNG cases have no emissions as they utilise already emitted CO2 (Case 1). In Case 2, CO2 emissions derive in the SNG process with the use of WGS and AGR in order to control the stoichiometric ratio (Case 2), while no direct emissions occur
for the SNG case (Case 3). It is noted that those emissions are neutral in the case that biomass is used as a fuel, but this value should be considered in a carbon footprint analysis. The investment cost indicated in Ta b l e 5 , consists of the equipment cost of all units of the plant, engineering, procure-ment and construction costs for the indi-vidual units and their integration. The in-vestment costs of the different units were scaled for the 50 MWth according to the scale factors and specific investment pub-lished in [10-14]. For the alkaline electro-lyser technology, investment costs slightly lower than 750 euros per kWel are reported by manufactures in [15] at current funding and without production scale-up.As operational cost (OC) or operation ex-penditure (OPEX) are considered the elec-tricity cost and the solid fuel cost which are varied. The cost of purchasing the biomass as well as the costs of handling and trans-portation are lumped summed indepen-dently of the distance and the transporta-tion of biomass. The labor costs and main-tenance costs were calculated in yearly basis and expressed in MWhSNG, account-ing 50.000 EUR/year for 18 people and 1 % of the capital cost respectively. The con-sumables, the labor and maintenance costs were summed up as fixed OC costs and no variation of the set values was performed as shown in Ta b l e 5 . The revenues are calculated according to the fixed fossil price of natural gas, to the fixed price of the heat provision to consumers and to the
Tab. 4. Combined Gasification and Power to SNG plant – Main Energy Flows – Case 2 and Case 3 [12].
No Case 2 Case 3 No Case 2 Case 3 No Case 2 Case 3
1 Air cooled
Air cooled
2 2.91 - 5.1 0.12 0.12
2 2.6 - 7 0.45 - 6.1 - -
4 4.25 10.45 5 1.096 1.096 7.1 - -
5 0.71 0.71 8.1 - -
6 0.67 0.67 2.1 0.007
7 0.596 0.46 1.1 7.38 34.76
8 1.76 0.32 3.1 - -
4.1 0.19 0.77
Total Energy Flows
SNG Biomass Steam Electricity CFE
MWth MWth MWth MWe %
Case 2 17.59 20 2.61 7.69 63.43
Case 3 32.12 20 8.82 35.65 57.67
Tab. 5. Techno-economic data for the three cases based on a 50 MWth SNG production.
Power to SNG Steam /Oxygen Gasification & Power to SNG-O2 Demand
Steam /Oxygen Gasification & Power to SNG-
Oversized Electrolysers
50 MWthSNG
Electricity Input (MWe) 95.16 21.86 55.5
Heat Output (MWth) - 7.41 13.73
Energy Conversion Efficiency
-Power plants 52.6 % - -
-Gasification plants - 72.8 % 73.5 %
CO2 utilisation direct indirect indirect
(ton CO2/ton product) 2.74
(ton CO2/GWhth product) 198
Direct CO2 emissions (kg/MWh product) 0 162.3 0
Specific investment cost (€/kWthSNG) 3222 4279 3506
Fixed OC (€/MWhthSNG) 8.12 9.17 8.39
Refence Values for all Cases Biomass: 31.65 EUR/MWhth – Electricity: 30 EUR/MWheHeat provision: 5 EUR/MWhth – Fossil NG: 30 EUR/MWhth
rate: 6 % – Tax Factor: 18 %
LCOE (€/MWh product)** 130.7 136.4 129.5
Ranking according to (Biomass >100 EUR/t & Electricity <30 EUR/MWhe)
1 2 3
Energy Storage (GWhe/year) (96 % availability)
800.3 183.8 466.7
* depending on low pressure and temperature or high pressure and temperature steam/O2 gasification**Biomass: 150 EUR/t, Electricity: 30 EUR/MWhe, Taxes:18 %
Renewable substitute natural gas synthesis VGB PowerTech 12 l 2018
marginal price of the fuel accounted as substitute for fossil fuels, which is varied. The price of the grid services in terms of primary and secondary control provided to the electricity grid and oxygen sales has not been considered. As presented in Ta -b l e 5 for the reference values, the current price of fossil natural gas cannot even cov-er the operational costs of SNG synthe-sis plants (reference of 30 EUR/MWhth), which also has been shown in the first 20 MWSNG demonstration plant GobiGas in Sweden operating with Scandinavian biomass prices [12]. In this regard, the marginal price of the fuel is calculated as an add on price to the product in or-der to show a viable business case and de-fine the levelized cost of SNG synthesis (LCOE).The investment is evaluated on the total costs including loan and not only on the
own capital. The following equations have been applied:
Where,Taxes(Tax)= (Revenues(R)-Operational Costs(OC)-Depletion(D)∙Tax Factor(TF)The levelized cost of energy (LCOE) is hereby defined as:
The lifetime of the investment is consid-ered at 20 years with 10 % remaining in-vestment value, while the pay out loan time at 8 years. A significantly high mar-ginal price for all the SNG cases is required, as these plants cannot have a profit even if
the capital costs were zero. The LCOE is presented for a variation of electricity and solid fuel prices, where heat provision has not been considered. As it is shown in F i g -u r e 7, comparing the three SNG cases on the influence of electricity and biomass prices, power to SNG (case 1) has always lower LCOE when the biomass price is over 150 EUR/ton and the electricity price low-er than 30 EUR/MWhe. For these reference values, Case 1 has a LCOE of 130.7 EUR/MWh, while the combined gasification and power to SNG with oversized electrolysers (case 3) has an LCOE of 129.5 EUR/MWh. In the case that electricity is bought at a price of of 20 EUR/MWhe, the price of bio-mass should be lower than 100 EUR/ton, in order to make the investment of the com-bined gasification and power to SNG with oversized electrolysers more viable. For the exact biomass price of 100 EUR/ton and
% Increase or Decrease of electricity streamcompared to the reference value
Cold
Fue
l Effi
cien
cy P
t SN
G in
%Co
ld F
uel E
ffici
ency
G&
Pt S
NG
in %
Cold
Fue
l Effi
cien
cy G
&Pt
SN
G in
%
Ener
gy C
onve
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n Ef
ficie
ncy
in %
Ener
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onve
rsio
n Ef
ficie
ncy
in %
Ener
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rsio
n Ef
ficie
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in %
Influence of Electricity Demandon CFE of Power to SNG - Case 1
Influence of Electricity and Heat Demandon ECE of Power to SNG - Case 1
Influence of Electricity Demandon CFE of Gasification and Power to SNG - Case 2
Influence of Electricity and Heat Demandon ECE of Gasification & Power to SNG- Case 2
Influence of Electricity and Heat Demandon ECE of Gasification & Power to SNG-Case 3
Influence of Electricity Demandon CFE of Gasification and Power to SNG - Case 3
% Increase or Decrease of electrolyser and heat dutiescompared to the reference value
% Increase or Decrease of electricity streamcompared to the reference value % Increase or Decrease of electrolyser and heat duties
compared to the reference value
% Increase or Decrease of electrolyser and heat dutiescompared to the reference value
% Increase or Decrease of electricity streamcompared to the reference value
Bild Fig. 1. Sensitivity analysis of the influencing parameters in the overall efficiency in the SNG production – Case 1 (top), Case 2 (middle) and Case 3 (below).
VGB PowerTech 12 l 2018 Renewable substitute natural gas synthesis
the electricity price of 20 EUR/MWhe, pow-er to SNG has a LCOE of 107.5 EUR/MWh, while the combined gasification and power to SNG with oversized electrolysers has an LCOE of 107.8 EUR/MWh. The only case, where the combined scheme with electro-lysers sized according to oxygen demand (case 2) has lower LCOE than the other cases is when electricity prices are over 30 EUR/MWhe and the biomass price is lower than 100 EUR/ton.A marginal price of 250 % to 300 % is re-quired for positive Net Present Values (NPV values). Biomass and electricity prices as well as taxation varying according to loca-tion play also an important factor on viabil-ity of SNG plants. A further reduction of specific capital costs with higher installed capacities, could allow a further reduction in the marginal price. It is noted that in the above considered cases, revenues from heat production have been considered at 5 EUR per MWhth heat and stable. However, high temperature steam is produced in all pro-cesses and a higher price in heat revenues can also be considered. Additional revenues from oxygen and grid services have not been considered. Finally in F i g u r e 8 , the LCOE of SNG production varying from 50 to 80 MWth scale is compared with the aver-age natural gas prices in Europe for house-holds (H -) and industrial (I -) consumers according to data from Eurostat. In addi-
tion, the abatement costs of CO2 for the ad-ditional premium price of 90 EUR/MWh correspond to 300 EUR/ton CO2.
Conclusions
Power to fuel technology can find applica-tions, where CO2 is available for pre- or post- combustion capture and can be opti-mally implemented in existing infrastruc-tures. The overall process integration of power to SNG resulted in an energy conver-sion efficiency 52.66 % for the lignite fired
plant. For the combined gasification and power to fuel technology, the Air Separa-tion Unit is replaced with oxygen provision from the electrolyser, the water gas shift catalytic system is considerably reduced or removed in the case of SNG production with oversized electrolysers and no CO2 emissions occur during the SNG produc-tion. The CFE of gasification and power to SNG ranges between 57.67 % to 63.43 % and with simultaneous heat provision, an ECE of 72.83 % and 73.51 % was calculat-ed. A potential increase or decrease of the
Influence of Electricity Prices in the LCOE for the three50MWth SNG Cases-(Biomass 150 EUR/ton)
Influence of Biomass Prices in the LCOE for the three50MWth SNG Cases-(Electricity 30 EUR/MWhe)
Influence of Biomass Prices in the LCOE for the three50MWth SNG Cases-(Electricity 20 EUR/MWhe)
Influence of Electricity Prices in the LCOE for the three50MWth SNG Cases-(Biomass 100 EUR/ton)
Leva
lised
Cos
t of E
nerg
yin
EUR
/MW
h thS
NG
% Increase or Decrease of electricity pricecompared to the reference value
Leva
lised
Cos
t of E
nerg
yin
EUR
/MW
h thS
NG
Leva
lised
Cos
t of E
nerg
yin
EUR
/MW
h thS
NG
Leva
lised
Cos
t of E
nerg
yin
EUR
/MW
h thS
NG
% Increase or Decrease of biomass pricecompared to the reference value
% Increase or Decrease of biomass pricecompared to the reference value
% Increase or Decrease of electricity pricecompared to the reference value
Fig. 7. Influence of electricity and biomass prices in LCOE of SNG cases.
EUR/
MW
h
RANGE OF LCOE SNG PRODUCTION120
100
80
60
40
20
0
H: Household with annual consumption: 5,600 kWh < consumption < 56,000 kWh (20 - 200 GJ), I: Industry with annual consumption: 2,778 MWh < consumption < 27,778 MWh (10,000 - 100,000 GJ),Source: Eurostat (online data code: nrg_pc_202 and nrg_pc_203)
EU-2
8Be
lgiu
mBu
lgar
iaC
zech
Rep
ublic
Den
mar
kG
erm
any
Esto
nia
Irela
ndG
reec
eSp
ain
Fran
ceC
roat
iaIta
lyLa
tvia
Lit
huan
iaLu
xem
bour
gH
unga
ryN
ethe
rland
sA
ustri
aPo
land
Portu
gal
Rom
ania
Slov
enia
Slov
akia
Finl
and
Swed
enU
nite
d Ki
ngdo
m
H-2014 H-2015 H-2016 I-2014 I-2015 I-2016
Fig. 8. Comparison of NG prices in EU countries with the range of LCOE for SNG production.
Renewable substitute natural gas synthesis VGB PowerTech 12 l 2018
electrolyser’s efficiency can influences sig-nificantly both processes. The SNG produc-tion costs cannot compete the price of fossil natural gas. For the production of renewa-ble fuels, the most important aspect on the comparison between renewable SNG pro-duction is the marginal or premium price, which is required to make such an invest-ment viable. Under the assumptions and cases present, for the 50 MWth SNG plants it was found that for a 150 EUR/ton biomass price, an electricity price of 30 EUR/MWhe and 18 % taxation, a marginal/premium price of 300 % of fossil SNG is required. This value can be optimized considering economy of scale, sales from steam and ox-ygen, grid services as well as tax exemp-tions. The final use of e-fuels in the trans-port sector, where fuel prices are signifi-cantly higher and the regulatory framework for fuel quality directives could provide the necessary incentives for the commercializa-tion of such technologies in a similar mar-ket model and end prices as biofuels.
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AbbreviationsAC Activated CarbonAEL Alkaline ElectrolysersAGR Acid Gas RemovalASU Air Separation UnitBTX Benzene, Toluene, XyleneCCS Carbon Capture and StorageCCU Carbon Capture and UtilisationCF Cash Flow
CFE Cold Fuel EfficiencyCR Capture RatioE EnergyECE Energy Conversion EfficiencyEU European UnionGHG GreenHouse GasH- HouseholdsHHV Higher Heating ValueHP High PressureHT High TemperatureHTS High Temperature ShiftI- Industrial ConsumersLCOE Levalised Cost of EnergyLHV Lower Heating ValueLNG Liquified Natural GasLP Low PressureLT Low TemperatureLTS Low Temperature Shift MDEA MethyldiethanolamineMT Medium TemperatureNEA National Energy AdministrationNG Natural GasNPV Net Present ValueOC Operational costsR RevenuesPEM Polymer Electrolyte MembranePCC Post-Combustion CapturePP Power PlantPtF Power to FuelPtSNG Power to SNGRES Renewable Energy SourcesRK-SOAVE Redlich-Kwong-SoaveRV Remaining ValueSNG Substitute Natural GasTax TaxesTF Tax FactorWGS Water Gas ShiftSymbols ExplanationC Carbon content on weight basisCl Chlor content on weight basisH Hydrogen content on weight basisIo Investment Costi Interest Ratem Mass flowN Nitrogen content on weight basisO Oxygen content on weight basisP PressureS Sulfur content on weight basisT TemperatureUnits Explanationbar bar unit for P°C Degree Celsius unit for TGW GigawattGWh Gigawatthourkg/s Mass flow in kilogram per secondkW kilowattkWh kilowatt hoursMJ Megajoulemol % Mole per centMW Megawatt electricMWh Megawatthour electricNm3 Normal cubic meterppm parts per millionVol % Volume per cent %w/w Weight to weight per cent (mass
based)Subscripts Explanatione electricF FuelG&PtSNG Gasification & Power to SNGin input out outputPtSNG Power to SNGth thermaltot total l
International Journal for Electricity and Heat Generation
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Vo lu me 89/2009 · ISSN 1435-3199
K 43600
In ter na tio nal Edi ti on
Focus: Power Plants in Competiton
New Power Plant Projects of EskomQuality Assurance for New Power PlantsAdvantages of Flexible Thermal Generation
Market Overview for Imported Coal
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Vo lu me 89/2009 · ISSN 1435-3199
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Focus: Furnaces, Steam Generators and Steam TurbinesUSC 700 °C Power Technology
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