IN
DEGREE PROJECT ENERGY AND ENVIRONMENT, SECOND CYCLE, 30 CREDITS
STOCKHOLM SWEDEN 2020,
Practical implementation of Bio-CCS in Uppsala
A techno-economic assessment ROBERT DJURBERG
KTH ROYAL INSTITUTE OF TECHNOLOGY
SCHOOL OF INDUSTRIAL ENGINEERING AND MANAGEMENT
I
Master of Science Thesis Department of Energy Technology
KTH 2020
Practical implementation of Bio-CCS in Uppsala A techno-economic assessment
TRITA: TRITA-ITM-EX 2020:400 Robert Djurberg
Approved
2020-06-30
Examiner
Björn Palm
Supervisor
Björn Palm
Industrial Supervisor
Nader Padban
II
III
Abstract
To decrease global warming, bioenergy with carbon capture and storage (Bio-CCS) has been proposed as an effective and necessary tool. Combusting biomass and capturing carbon dioxide (CO2) from the same process results in net negative emissions, hence, reducing the concentration of CO2 in the atmosphere.
The infrastructure around heat and power generation in Sweden has transformed to make use of biomass and waste. Bio-CCS has the potential to be a key factor in making the heat sector carbon negative and the Swedish energy system more sustainable.
This study has assessed how Bio-CCS can practically be implemented in the Uppsala heat and power plant. In the assessment, three chemical absorption post-combustion carbon capture (CC) technologies were evaluated based on energy requirement, potential to reduce emissions and economics. They are the amine process, the chilled ammonia process (CAP) and the hot potassium carbonate process (HPC).
The process of each technology was modelled by performing mass and energy balance calculations when implementing CC on the flue gas streams of the production units using biomass-based fuel at the plant.
The modelling enabled finding specific heating, cooling and electricity requirements of the technologies.
With this data it was possible to assess the potential emission reduction and CC cost for the different configurations assessed.
A solution was proposed in how a CC technology can be integrated into the system of the Uppsala plant regarding land footprint, available heat supply to the process and possibilities for waste heat recovery. If heat recovery is not utilized the results show that the amine process is the most cost-effective technology when implemented on the flue gas stream of the waste blocks. When utilizing heat recovery to use waste heat to heat the district heating water, CAP becomes more cost-effective than the amine process. Further improvements can be achieved by combining flue gas streams of the waste blocks to increase the number of hours per year CC can be performed. The plant in Uppsala can then capture 200 000 tonne CO2
annually. The total cost of Bio-CCS will be approximately 900 SEK per tonne CO2 captured.
Keywords
BECCS, Bio-CCS, CCS, techno-economic assessment.
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Sammanfattning
För att minska den globala uppvärmningen har infångning och lagring av koldioxid från förbränning av biomassa (Bio-CCS) föreslagits som ett effektivt och nödvändigt verktyg. Förbränning av biomassa och infångande av koldioxid från samma process leder till negativa nettoutsläpp, vilket minskar
koncentrationen av koldioxid (CO2) i atmosfären. Infrastrukturen kring värme- och kraftproduktion i Sverige har omvandlats till att använda biomassa och avfall. Bio-CCS har potential att vara en nyckelfaktor för att göra värmesektorn koldioxidnegativ och det svenska energisystemet mer hållbart.
Denna studie har analyserat hur Bio-CCS praktiskt kan implementeras i Uppsalas kraftvärmeverk. I analysen utvärderades tre infångningstekniker av typen kemisk absorption baserat på energibehov, potential att minska utsläpp och ekonomi. Teknikerna är aminprocessen, chilled ammonia process (CAP) och hot potassium carbonate process (HPC).
Processen för varje teknik modellerades genom att utföra mass- och energibalansberäkningar vid infångning av CO2 från rökgasströmmarna producerade av produktionsenheterna som förbränner biomassa. Modelleringen gjorde det möjligt att hitta specifika värme-, kyl- och elbehov för teknikerna.
Med dessa data var det möjligt att bedöma den potentiella utsläppsminskningen och kostnaden för infångning för de olika konfigurationer som har analyserats.
En lösning föreslogs i hur en infångningsanläggning kan integreras i kraftvärmeverkets system när det gäller markanvändning, tillgänglig värmeförsörjning till processen och möjligheter till återvinning av spillvärme. Om värmeåtervinning inte utnyttjas visar resultaten att aminprocessen är den mest kostnadseffektiva tekniken när den implementeras på rökgasströmmen från avfallsblocken. När man använder värmeåtervinning för att använda spillvärme för att värma fjärrvärmevattnet blir CAP mer kostnadseffektivt än aminprocessen. Ytterligare förbättringar kan uppnås genom att kombinera rökgasströmmar från avfallsblocken för att öka antalet timmar per år infångning kan utföras.
Anläggningen i Uppsala kan då årligen fånga 200 000 ton CO2. Den totala kostnaden för Bio-CCS kommer att vara cirka 900 SEK per ton infångad CO2.
Nyckelord
BECCS, Bio-CCS, CCS, teknoekonomisk analys.
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Acknowledgement
This master’s thesis is the finale of my journey at the Royal institute of Technology. The thesis is a part of the master’s programme Sustainable Energy Engineering within the division of Heat and Power Technology at the School of Industrial Energy Engineering and Management, KTH. The thesis was performed within the department of Research and Development at the energy company Vattenfall.
I would like to take this moment to show my gratitude to everyone that has contributed to the creation and completion of this thesis.
To my supervisor at Vattenfall, Nader Padban for tremendous guidance, support and inspiration throughout the project.
To the employees at Vattenfall Research and Development department for supporting me and making the time at the department exciting and productive.
To the Vattenfall Heat department, especially the plant engineers in Uppsala for helping me at the plant and for contributing to rich discussions.
To my supervisor at KTH, Professor Björn Palm at the department of Energy Technology for guidance and feedback.
Finally, to my family and friends for supporting me in my journey of becoming an engineer. Thank you.
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Abbreviations
Bio-CCS – Bioenergy with carbon capture and storage CAP – Chilled ammonia process
CAPEX – Capital expenses CC – Carbon capture
CCS – Carbon capture and storage CCU – Carbon capture and utilization CH3OH – Methanol
CHP – Combined heat and power CO – Carbon monoxide
CO2 – Carbon dioxide CO32- – Carbonate
COP – Coefficient of performance GHG – Greenhouse gas
H2 – Hydrogen
HCl – Hydrochloric acid HCO3- – Bicarbonate
HPC – Hot potassium carbonate
IGCC – Integrated gasification combined cycle K2CO3 – Potassium carbonate
MEA – Monoethanolamine MGS – Membrane gas separation NOx – Nitrogen oxides
VII N2 – Nitrogen
NaOH – Sodium-hydroxide NH3 – Ammonia
(NH4)2CO3 – Ammonium carbonate NH4HCO3 – Ammonium bicarbonate OPEX – Operating expenses
PZ – Piperazine SO2 – Sulphur oxide SEK – Swedish krona
TRL – Technology readiness level WGS – Water-gas shift
VIII
Table of contents
1 Introduction ... 1
1.1 Purpose ... 1
1.2 Research question ... 1
1.2.1 Limitations ... 2
1.3 Methodology ... 2
2 Technological background ... 3
2.1 Carbon capture ... 3
2.2 Separation method ... 5
2.2.1 Absorption ... 5
2.2.2 Adsorption ... 6
2.2.3 Membrane ... 7
2.2.4 Distillation and Cryogenic ... 7
2.3 Uppsala plant ... 8
2.3.1 Delivered energy ... 8
2.3.2 Fuel mix ... 8
2.3.3 Production units ... 9
2.3.4 Load factor and future operation ...12
2.3.5 Retrofittability in the Uppsala plant ...13
2.3.6 Flue gas ...13
2.3.7 CO2 transport and storage ...15
2.3.8 Land use requirement ...16
2.3.9 Energy integration regarding the CC technology ...17
3 Technology assessment ...19
3.1 Process description ...20
3.1.1 Amine process ...20
3.1.2 Chilled ammonia process ...23
3.1.3 Hot potassium carbonate process ...24
3.2 Energy assessment ...25
3.3 CO2 reduction assessment ...26
3.4 Cost assessment ...27
4 Result and discussion ...30
4.1 Energy assessment ...30
4.1.1 Amine process ...30
4.1.2 Chilled ammonia process ...31
4.1.3 Hot potassium carbonate ...31
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4.1.4 Comparison ...32
4.2 CO2 reduction ...33
4.3 Cost assessment ...34
4.3.1 Sensitivity analysis ...37
4.4 Energy integration ...38
4.4.1 Heat supply ...39
4.4.2 Waste heat recovery ...39
4.4.3 CO2 reduction ...41
4.4.4 Cost assessment...42
4.4.5 Sensitivity analysis ...43
4.5 CC integration in the Uppsala plant ...44
4.5.1 Available space ...44
4.5.2 Process integration ...45
4.5.3 Combining flue gas streams ...46
4.6 Total cost of CCS ...48
5 Conclusion ...49
5.1 Future work ...50
X
Table of Figures
Figure 1 Alternatives for CC in power generation (Rackley, 2017) ... 4
Figure 2 Uppsala district heating network (Vattenfall, 2018) ... 8
Figure 3 Fuel mix for heat and power production in Uppsala, 2020 (Padban, 2020) ... 9
Figure 4 Modified map of the Uppsala plant in Boländerna (Eniro, 2020) ... 9
Figure 5 Waste management process of Block 1 and 4 (Vattenfall, 2016) ...10
Figure 6 Waste management process of Block 5 (Vattenfall, 2016) ...10
Figure 7 Heat production process of HVC (Vattenfall, 2016) ...12
Figure 8 District heating production 2019-2023 (Padban, 2020). ...13
Figure 9 Comparison in cost of different methods of CO2 transportation including investment cost (Svensson el al. 2005) ...15
Figure 10 Waste heat recovery technologies (Brückner, 2015) ...18
Figure 11 Flow diagram of the amine process (IEAGHG, 2019a) ...21
Figure 12 Flow diagram of CAP (Augustsson et al., 2017) ...23
Figure 13 Flow diagram of HPC (Smith et al., 2016) ...24
Figure 14 Energy requirement of the amine process ...30
Figure 15 Energy requirement for CAP ...31
Figure 16 Energy requirement for HPC ...32
Figure 17 Detailed comparison of energy requirement for CO2 separation from flue gas, Block 1 and 4 ...32
Figure 18 Net CO2 emissions from each production unit ...34
Figure 19 Cost comparison between different capture capacities ...35
Figure 20 Optimal capture cost for each CC technology and flue gas stream ...35
Figure 21 Cost breakdown of the amine process at a capture capacity of 20 tonne per hour...36
Figure 22 Cost breakdown of CAP at a capture capacity of 20 tonne per hour ...36
Figure 23 Cost breakdown of HPC at a capture capacity of 20 tonne per hour ...36
Figure 24 Sensitivity of CC cost of the amine process on block 1 and 4 ...37
Figure 25 Sensitivity of CC cost of CAP on block 1 and 4 ...38
Figure 26 Sensitivity of CC cost of HPC on block 1 and 4 ...38
Figure 27 a) Electricity consumption and b) Power demand before and after heat recovery on B 1,4 ...41
Figure 28 Sensitivity of CC cost of the amine process on block 1 and 4, with heat recovery ...43
Figure 29 Sensitivity of CC cost of CAP on block 1 and 4, with heat recovery ...44
Figure 30 Sensitivity of CC cost of HPC on block 1 and 4, with heat recovery ...44
Figure 31 Modified map of Uppsala plant where locations of production units and available space for a CC unit is marked (Eniro, 2020) ...45
Figure 32 Process waste heat integration to the district heating network. ...46
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Table of tables
Table 1 Year of reconstruction and effect of the assessed production units, thermal effect includes flue gas
condensation ...13
Table 2 Flue gas characteristics ...14
Table 3 TRL of different CC technologies (IEAGHG, 2019a) ...19
Table 4 Advantages and disadvantages of chosen technologies ...20
Table 5 Overview of amine-based post-combustion CC technologies (IEAGHG, 2019a)...22
Table 6 General parameters for the energy assessment ...25
Table 7 Parameters for the different process ...26
Table 8 Emission factor of different fuels and electricity (Energiföretagen, 2019a; Energimyndigheten, 2019a). ...27
Table 9 Assumptions for the economic assessment ...29
Table 10 Capacity factor for the production units ...33
Table 11 Process cooling requirement and potential waste heat recovery. ...39
Table 12 Net CO2 emissions with heat recovery ...42
Table 13 CC cost with heat recovery ...42
Table 14 Result when combining the flue gas streams of waste block 1,4 and 5 with heat recovery ...47
Table 15 Total cost of CCS with heat recovery ...48
1
1 Introduction
In December 2015, a momentous agreement was reached between 195 countries to combat climate change and to increase the actions and investments necessary for a sustainable future. The Paris Agreement’s key goal is to decrease global warming by keeping a global average temperature well below 2 degree Celsius above pre-industrial levels and preferably limit the increase to 1.5 degree Celsius, acknowledging that this greatly reduces the risk and impact of climate change (IPCC, 2018). To successfully achieve the previously named goal, parties will have to decrease greenhouse gas (GHG) emissions as soon as possible.
Ahead of the climate conference in Paris the Swedish government created a platform for communication and cooperation between actors called Fossil Free Sweden to show how cities, organizations and enterprises could contribute to sustainability. The Swedish parliament decided in 2017 to adopt a new climate policy framework with a long-term target of net zero GHG emissions by 2045 (The Swedish Government, 2017).
As a reaction to the adopted framework Fossil Free Sweden started to develop roadmaps for how Swedish industries will be fossil free with increased competitiveness as a result. One of the industries that developed a roadmap was the heating industry. The roadmap consists of agreed commitments that the industry will undertake to become fossil free by 2030 and function as a carbon sink by 2045 to decrease the Swedish total GHG-emissions (Fossilfritt Sverige, 2018). To succeed with the goals the heating industry must remove fossil fuels in the production chain and provide services that can contribute to negative emissions. Bio-CCS is one type of technology that can provide such a service, considering the life cycle emissions of the biomass fuel. Bio-CCS can also be referred to as BECCS. The concept of Bio-CCS is as followed: CO2 is captured by the biomass, through the photosynthesis process, as it grows. When the biomass is combusted at a power plant to produce heat and/or electricity CO2 is produced in the process. Capturing CO2 from the flue gas stream will result in net negative GHG-emissions.
The Nordic region is a suitable location for development and deployment of Bio-CCS. The region has developed a world-leading biomass and waste fuelled combined heat and power (CHP) infrastructure and has vast resources of forest residues that can be used to produce heat (Rydén et al., 2017). It is of interest to investigate the possibilities of CC technologies in Sweden as it has great potential to reduce total national GHG-emissions as it is one of the few technologies that can function as a carbon sink in the energy sector (Fossilfritt Sverige, 2018). This report will investigate the possibilities of Bio-CCS in Sweden by doing a case study of the plant in Uppsala owned and operated by the Swedish energy company Vattenfall.
1.1 Purpose
The aim of this study is to investigate what CC technology is most feasible to integrate into the Uppsala plant with regards to economic and technological aspects, maturity and retrofittability. The results will deliver suggestions for retrofitting of the power plant and provide a base for decision-making for Vattenfall and Uppsala municipality.
1.2 Research question
In order to fulfil the aim of the study a techno-economic analysis will be performed to answer the research questions:
Which is the most suitable CC technology to integrate into the Uppsala plant?
Where in the Uppsala plant should the CC system be integrated and how can it be done?
Sub-questions that will be of importance when finding the answer of the research questions:
What are the energy requirements of the technologies assessed per tonne CO2 captured?
What are the possibilities for waste heat recovery from the CC technologies;
and from where can energy required by the CC technologies be taken?
2 1.2.1 Limitations
This study will have the following limitations:
The focus of this study will be to investigate CC technologies in the assessment. Thus, transportation and end storage of CO2 will only be briefly covered.
CC technologies that are far from market deployment and are not suitable for retrofitting will not be covered in the assessment as the study should function as support for near future decision- making.
The assessment will focus on the three chemical absorption processes: the amine process, CAP and HPC. The reason for this is explained in section 3.
1.3 Methodology
In order to fulfil the aim of the study, following steps will be carried out throughout the project:
Firstly, a literature study will be performed to gather the necessary information about CCS and CC technologies.
Gathering of necessary data from the Uppsala plant will be done by doing site visits. Data from different processes will be extracted from the plant’s operational system. In addition, data will be gathered by doing interviews and receiving simulated production plans from Vattenfall.
A techno-economic model will be developed to be able to perform the assessment. The model will consider aspects such as energy requirement, mass and energy flows and fluid characteristics.
The techno-economic assessment will be performed to assess the most feasible system with regard to energy requirement, potential to reduce CO2 emissions and cost. A sensitivity analysis will be performed to evaluate the model’s stability and the reliability of the analysis.
Section 3 will present a thorough explanation of what aspects the model will comprise and how assessment will be done.
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2 Technological background
This section will introduce methods of CC and different technologies that can be used in a heat and power plant.
2.1 Carbon capture
There are several naturally occurring processes that capture atmospheric CO2 and stores it in the oceans, forests and soils. With the increased amount of emissions from human activities the earth’s natural carbon sinks struggle to keep the CO2 concentration down which in the end leads to global warming. There are technologies that can be used to capture CO2. They can be used to reduce the concentration of CO2 in the atmosphere or to remove CO2 from a process stream. These technologies will play an essential part in reducing GHG-emissions in industrial processes. Heat and power production often involve combustion of fuels, in the combustion process the chemical energy of the fuel is converted to heat, water steam and CO2. There are four main approaches to CC in carbon-based power production, they are illustrated in Figure 1.
Post-combustion capture is when CO2 is separated from the flue gases after the combustion. Usually the product gas is discharged to the atmosphere after SO2, NOx and fly ashes are removed. In this case the gas, typically with a CO2 concentration of 5-15 %, is passing through a device that separates the CO2 from the gas (Rackley, 2017). After the separation the flue gas, which now mainly consists of nitrogen (N2), is discharged to the atmosphere and the CO2 can be transported to a storage site.
Pre-combustion capture is when CO2 is separated before the combustion. The primary fuel is decarbonated in a gasification process for solid fuels and a reforming process for gaseous fuels to produce a mixture of H2 and CO called syngas. CO can then be included in a water-gas shift reaction (WGS) to produce H2 and CO2 (Rackley, 2017). In this stage the CO2 can be separated and stored and the H2 can take part of a combustion process or be stored as a fuel for later use. The main research area of pre-combustion capture in power production is to use it with integrated gasification combined cycles (IGCC). This approach is interesting because of the higher partial pressure of CO2 in the gas which makes the process more cost- effective due to lower energy requirement for separation and compression of CO2 (Sifat & Haseli, 2019).
Oxyfuel combustion is when a fuel is combusted solely in O2 instead of air which make the flue gas comprise of CO2, steam and possibly SO2 and NOx (Rackley, 2017). The flue gas is cooled and compressed below its water dew point so that the water can be removed. The remaining impurities are removed in the same manner as in post-combustion capture. The resulting gas consists of CO2 that can be stored. The O2
used in the combustion need to have a purity of around 95-99 % (IPCC, 2005). This allows not only the flue gas to have CO2 concentration of greater than 80 % but also higher combustion temperature with less fuel as there is no N2 that is heated (ibid.).
Chemical looping combustion is the newest approach to separate CO2 in power generation. Chemical looping uses the same principal as oxyfuel combustion which is letting the fuel combust in oxygen and produce a flue gas with high concentration of CO2. How the oxygen is separated from the air stream is how the approaches differ. While oxyfuel combustion uses a separate air separation unit to produce oxygen, chemical looping uses a metal oxide carrier. A compressed air stream is introduced to a metal, possibly iron, nickel or beryllium, to oxidize in an exothermic reaction (Rackley, 2017). The metal oxide is then carried to the combustion reactor to oxidize a fuel, for instance methane, in an exothermic or endothermic reaction depending on which metal is used. In the combustion the metal oxide is reduced, and the metal is looped back to re-oxidize with the air stream.
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Figure 1 Alternatives for CC in power generation (Rackley, 2017)
Pre-combustion, oxyfuel and post-combustion capture have specific requirements for retrofitting. Space requirements are necessary for each approach due to additional equipment, for instance, WGS reactors for pre-combustion gasification, air separation units for oxyfuel and absorption scrubbers for amine-based post- combustion capture. Space due to compression, transport and local storage of CO2 will also have to be considered.
For oxyfuel CC, modifications to the combustor and boiler will be necessary. The use of O2 will increase the combustion temperature which can damage the material of a combustor, minimizing air leakage into the system is also critical (Rackley, 2017). Oxyfuel combustion has desirable conditions for CC as it produces high concentration of CO2. The main issue for retrofitting oxyfuel combustion is that the production unit need to be significantly modified to manage operating conditions. Another drawback is the high electric energy requirement of the air separation unit. Cryogenic air separation is the most mature method, it will most likely require electricity as energy source for the chillers. Access to electricity must be ensured for air separation.
For an IGCC to be pre-combustion capture retrofitted a WGS reactor is needed to be integrated between the gasifier and the combustor. Additionally, the gas turbine must be capable to handle H2-firing (Rackley, 2017). Pre-combustion capture is an approach with great advantages such as low energy requirement of separation and compression, however, it is restricted to plants of the type IGCC.
For post-combustion capture, access to low pressure steam or hot water is important for many of the regeneration processes of solvents. Extracting steam or hot water will impact the heat production at the plant. Therefore, considerations must be taken when planning the production so heat demand will be met.
Post-combustion capture is the only approach that separates the CO2 from a heat and power production unit without altering the combustion process, thus, could be implemented on most existing power production processes. Even after extensive refurbishment of a production unit a post-combustion
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separation could still be fit to operate with it. Additionally, the post-combustion is the only approach for CC that is fully commercial in power production (Bui et al., 2018a).
2.2 Separation method
Methods for separating CO2 from gas streams have been in practice for a long time. For instance, chemical and physical absorption systems have been used for more than 50 years. The methods were developed to treat natural gas so it would have low concentration of acid gases, thus improving the quality of the gas (Rackley, 2017). Different kinds of separation methods have been developed and there are numerous methods in development, with new design and materials used in the process. The main categories of separation methods will be presented in the following segment.
2.2.1 Absorption
Absorption processes have typically been used to separate acid gas with relatively high partial pressure from a process stream. Due to the extensive use of absorption in the oil and gas industry the method has provided a body of knowledge to the CC technologies used and is in development today.
Chemical and physical based reaction are two types of CO2 absorption. The solvent can chemically react with the sorbate, in this case CO2, to form a chemical compound or absorb the sorbate without a chemical reaction. The key requirements that make a solvent effective are fast reaction rate, high loading capacity and low regeneration energy.
2.2.1.1 Chemical absorption
The solvent and CO2 are reacting, exothermically, in a gas stream to form a compound. A low temperature is desirable in this stage (Rackley, 2017). The process can later be reversed at higher temperature in a regeneration or stripping process. At low CO2 partial pressure chemical absorption have shown to be effective, usually with amine and carbonate-based solvents.
Amine-based solvents formally derives from NH3, the difference is that one or more hydrogen atoms are substituted by organic components to form compounds of amines. Depending on the number of substituted hydrogen atoms the amines are classified as primary, secondary or tertiary amines. In general, the reaction rate is fast for primary amines followed by secondary and tertiary amines. However, loading capacity and regeneration energy are more favourable for tertiary amines followed by secondary and primary amines.
Monoethanolamine (MEA) is one of the most applied amines for CC and the MEA process is the most extended in post-combustion processes and often functions as a benchmark for the absorption solvents (Luis, 2015). MEA is a primary amine and functions as a weak base that neutralizes an acidic substance such as CO2 in an aqueous solution.
MEA became popular because of high reaction and absorption rate combined with low cost. It is however subjected to drawbacks such as high regeneration energy, limited CO2 loading capacity and high toxicity if inhaled. The solvent is also prone to cause corrosion and fouling and degrade in presence of O2, SO2 and NOx (Sreedhar et al., 2017).
Carbonate-based absorption is another method of chemical absorption. Here carbonates have been used as solvent for CO2 removal, the carbonate solution is able to regenerate in a similar way as the amine-based solvents. One carbonate-based solvent that has been emerging in flue gas CO2 treatment is aqueous potassium carbonate (K2CO3). Comparing to amine-based solvents the main benefits of K2CO3 are that the solvents heat of absorption is lower which results in less energy penalties in the regeneration process (Sreedhar et al., 2017). The solvent is also considered because its relatively low cost, low toxicity, high resistance to degradation and little corrosion concern (ibid.). The major disadvantage is the low mass transfer rate and reaction rate at lower CO2 pressures (Rackley, 2017). Therefore, aqueous K2CO3 has been used especially for bulk CO2 capture. However, adding so called promoters to improve the performance of the solvent is possible. The blend of solvents gets more desirable characteristics, usually by blending amines
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with carbonate or by blending primary, secondary and tertiary amines. Piperazine (PZ) is one solvent that has been frequently used as a promoter for CO2 removal. For instance, in combination with K2CO3 resulting in increased rate of absorption and absorption capacity (Rackley, 2017).
Aqueous ammonia-based absorption has been proposed as an alternative to the traditional amine-based technology. The ammonia-based reaction requires significantly less energy in the regeneration process, the solvent is also cheaper and does not degrade and cause corrosion as much as an amine-based solvent (Gaspar et al., 2014). Using ammonia as a solvent can also synergize with flue gas treatment of SO2 and NOx as some scrubbers are ammonia-based, this allows for a single solvent system for flue gas treatment (Rackley, 2017).
Perhaps the most interesting variant of aqueous ammonia CO2 capturing is the Chilled ammonia process (CAP). In the process, CO2 is captured at a low temperature, preferably below 10 °C. Keeping a cold temperature process has the advantage of reducing ammonia slip, which is a problem for ammonia-based systems, in the absorber and reducing the volume of the flue gas (Gaspar et al., 2014). The unreacted ammonia emitted from a process is called ammonia slip, it is important to minimize this to avoid damaging downstream components and ammonia emissions. The main disadvantages are energy use related to cooling the gas and washing plus regeneration of the washing water because of ammonia slip (ibid.).
Sodium hydroxide-based absorption utilizes the reaction between sodium-hydroxide (NaOH) and CO2
to produce carbonates (CO3 2-) and bicarbonates (HCO3-), the end products can be controlled by adjusting the pH level by adding acids like hydrochloric acid (HCl) (Rackley, 2017). The regeneration process is performed by adding lime (CaO) to the products. The aqueous carbonate slurry must then be heated to remove water followed by calcination. The greatest advantage of this kind of absorption is that the solvent is abundant and inexpensive, however, high energy requirement in the regeneration process compared to other chemical absorption methods makes it ineffective (Rackley, 2017).
2.2.1.2 Physical absorption
Rather than chemically reacting with a gas, physical solvents absorb by applying high pressure and concentration of the sorbent. CO2 solubility follows the principles of Henry’s law, which states that the amount of gas dissolved in a solvent is proportional to the partial pressure of the gas in equilibrium of the solvent at a given temperature and volume (Rackley, 2017). Methanol (CH3OH) can be used as a solvent to remove CO2 from a stream, for instance when treating natural gas. Operating conditions can be a combination of low temperature and high pressure to enable an effective separation of CO2. Changing the operating conditions to higher temperature or lower pressure, will result in lower solubility and release of CO2. Usually the absorption and regeneration process are achieved by changing the temperature (temperature swing) or changing the pressure (pressure swing). Other processes that are utilizing physical solvents are the Fluor process that is using pylene carbonate, and the Selexol process that is using dimethyl ethers of polyethylene glycol. These solvents are used in production of ammonia, methanol and hydrogen.
However, the solvents have shown potential to be effective in pre-combustion capture for IGCC (Plaza et al., 2016). As the physical solvent is chemically inert the process will not produce heat-stable salts which can be the case for chemical absorption (Rackley, 2017).
2.2.2 Adsorption
Instead of being dissolved by or absorbed into the bulk of a solvent, adsorption is the adhesion of atoms or molecules from a sorbate on the surface of the sorbent. Between the sorbent and the sorbate adsorption can either be through a chemical bond or physical attractive force, for instance van der Waals bonds.
Adsorption has been used for a long time to separate or purify gas in industrial processes such as air purification. The sorbent can either be solid or liquid, but solid sorbents have shown many important advantages. In general, the solid sorbents can operate at a wider temperature range, are less problematic to dispose and are environmentally benign (Rackley, 2017). There has been an increase in use of adsorption for gas separation, which has led to new sorbents being developed with a more diverse range of process options and application areas. CO2 removal is one application that is proposed as a promising alternative to conventional amine-based absorption. Advantages of adsorption includes high adsorption capacity at
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ambient conditions, minimized pressure losses and overall reduction in cost of CO2 separation and regeneration energy (Jiang et al., 2019) (Rashidi & Yusup, 2016). Two interesting physical sorbents for post- combustion capture are activated carbon and zeolites as they are effective in low temperature conditions, environmentally friendly and have a relatively low production cost (Rashidi & Yusup, 2016). Activated carbon also has the advantage of being hydrophobic which makes in redundant to remove potential moisture in the flue gas stream. Post-combustion CO2 removal based on adsorption is now undergoing commercialization. There are lab-scale prototypes of chemical adsorption processes, as for activated carbon the process has only been tested in theory (Jiang et al., 2019).
2.2.3 Membrane
Membranes work as a filter that allows specific molecules from a stream to permeate through the membrane.
This separation method is relatively new for treating gas. It was developed for hydrogen separation but has also been used for oxygen/nitrogen separation, separation of CO2 from natural gas and for enhanced oil recovery (Rackley, 2017). The development of composite polymer membrane became a breakthrough for large-scale industrial application. These membranes are often called selective membranes and have a thin selective layer that is performing the separation and a thicker layer that provides mechanical support.
Membranes for CC in power production are not yet market ready. However, numerous publications of membrane gas separation (MGS) for CO2 have been completed the last 20 years (Siagian et al., 2019). The publications mainly cover research on treatment of natural gas but also applications for power production.
Both for post-combustion capture separating CO2/N2 or CO2/N2/O2 and pre-combustion capture separating CO2/H2. The main limitation for commercializing membrane separation in post-combustion is the requirement of high selectivity in the flue gas, which has relatively low concentration of CO2 (Siagian et al., 2019). Membranes could then become a competitor to absorption as the technology is cost and energy effective as they don’t need to be regenerated and they don’t need solvents. Operating flexibility and modularity are also characteristics that makes membranes interesting (ibid.).
2.2.4 Distillation and Cryogenic
Distillation techniques has been used for a long time for separation of liquids. The development of modern, large-scale methods began in the 19th century for industrial chemical and alcohol production (Rackley, 2017). Cryogenics is a term that is sometimes used to describe distillation processes with very low operating temperature. Distillation can be useful for CC in two ways, either by cryogenic air separation to produce O2
for oxyfuel combustion or to capture CO2 by cooling a stream in a cryogenic phase separation process. The fundamental separation process depends upon the volatility and boiling point of a substance in a liquid mixture. When separating O2 from air the operating temperature at normal pressure will be between -195.8
°C and -183.0 °C, the boiling point for N2 and O2 (Rackley, 2017). Operating temperature for CO2 separation is easier to obtain as the boiling point for CO2 is -78.5 °C at normal pressure (ibid.). The main benefit of cryogenic CO2 capture is the state and quality of the product. CO2 can either be captured as liquid, solid or a slurry with a purity of over 99.9 % (Song et al., 2019). These conditions are beneficial for transportation, storage and utilization of CO2. As the process involves liquefaction at low temperature an additional compression step can be avoided before transport, thus, a reduced energy penalty. The technology requires a substantial amount of energy for the cryogenic process. Liquified natural gas can be used as a cryogenic source with the downside of high dependency on the scale and location of the natural gas production facility.
An alternative is the refrigeration process using electric coolers to produce the thermal energy. The coefficient of performance (COP) is typically around 0.4 which means that an addition of electric energy more than twice as large as the useful thermal energy is needed (Song et al., 2019). Having access to cheap electricity could be a reason for cryogenic separation instead of heat driven processes such as amine absorption.
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2.3 Uppsala plant
The Uppsala heat and power system consists of a district heating network together with several production units for district heating and cooling, steam and electricity. In general, the production is operated to meet the demand for steam, district heating and cooling. The main production facility is in the district Boländerna since 1960s. There is also a smaller production facility in the district Husbyborg and a production unit at the municipal water treatment plant.
2.3.1 Delivered energy
District heating and cooling: Close to 90 % of Uppsala heating demand is met by district heating. The network comprises approximately 450 km piping in which hot water is transported, supply and return temperature is around 80 °C and 45 °C but fluctuates over the season. The network is shown in Figure 2.
In 2018 the district heating network delivered 1307 GWh (Vattenfall, 2018). There is also a district cooling network that delivers water with temperature of 6 °C corresponding to 60 GWh yearly (ibid.). Accumulator tanks for hot and cold water are installed to even out the peak demand from district heating and cooling and reduce the use of peak production units.
Figure 2 Uppsala district heating network (Vattenfall, 2018)
Steam: Process steam with pressure of 15 bars and temperature of 210 °C is produced and delivered in culvert piping system to industrial customers in Uppsala. 101 GWh process steam was delivered in 2018 (Vattenfall, 2018).
Electricity: Steam can be used to produce both heat and electricity simultaneously. Electricity can be used locally by the plant or be delivered to the Uppsala distribution grid. Net electricity production to the grid was 191 GWh in 2018 (Vattenfall, 2018).
2.3.2 Fuel mix
In the beginning of the 1980s the Uppsala energy system was dependent on fossil oil for heat and power production. Oil was successively replaced by mainly coal, peat and waste in the late 1980s. The past decade the dominating fuel has been waste followed by peat. In the last few years heavy investments have been done to increase the use of biomass as fuel (Vattenfall, 2018). The fuel mix of the heat and power production at the Uppsala plant for the year 2020 is shown in Figure 3. All the hot water boilers fuelled by fossil oil
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have been or are going to be converted to bio oil and the peat fuelled hot water boiler was converted to wood pellets during 2019 (Vattenfall, 2018).
Figure 3 Fuel mix for heat and power production in Uppsala, 2020 (Padban, 2020)
2.3.3 Production units
The power plant in Boländerna comprises many different power production units, fuel storages and thermal energy accumulators. This section will describe the production units using biomass and waste as fuel.
Figure 4 shows the layout of the Uppsala plant. The four production units that will be included in the assessment are marked on the map.
Figure 4 Modified map of the Uppsala plant in Boländerna (Eniro, 2020)
Waste-to-energy units: Waste management has been performed at Boländerna since 1961 and today steam, electricity and heat for district heating and cooling are produced. There is a total of three lines running
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on waste, two older called Block 1 and 4 and a newer called Block 5. The energy recovery from waste serves as a baseload production year-round.
Block 1 and 4 were built in 1983 and 1982, the lines have a shared flue gas treatment and flue gas condenser.
The waste management process of Block 1 and 4 is shown in Figure 5. The process of Block 5 is shown in Figure 6.
Figure 5 Waste management process of Block 1 and 4 (Vattenfall, 2016)
Figure 6 Waste management process of Block 5 (Vattenfall, 2016)
Waste is delivered to the plant, weighed and registered. Trucks unload the waste into bunkers where waste can be stored or fed to the incinerator. The bunkers of Block 1 and 4 have a capacity of around 1600 tonnes and is enough fuel for two days of full operation. Block 5 can store 2500 tonne waste which is equivalent to four days of full operation.
The combustion takes place in moving grate incinerators. Combustion air is supplied from underneath the grate and continues upwards. The combustion takes place in temperatures of around 900-1000 °C. Bottom ash is the non-combustible residue of the waste, it is removed at the bottom of the moving grate but also when it falls through the grate sieve. The combustion gas is treated with a solution of urea in Block 1 and 4 on its way to the steam boiler. This is done to reduce the amount of NOx in the gas, recirculation of the combustion gas is also performed to achieve less NOx from the combustion. In Block 5, the flue gas is treated with ammonia to reduce NOx in a selective catalytic reduction between the fabric filter and economizer.
Förbränningsluft Urea- insprutning
Ånga ut till kunder
Elektrofilter Avgaspanna Rökgas- kondense- ring
Textilt spärrfilter
Skorsten
Rökgas- fläkt
Vattenbehandling Absorptions-
värmepump
Akti vt kol Kalk Aska
Bottenaska Avfalls-
bunker
Luftinblåsning Rökgasåterföring
Energin i ångan vä xlas till fjärrvärme
Fjärrvärme Pann-
tuber 1000oC
140oC Förbränningsluft
Urea- insprutning
Ånga ut till kunder
Elektrofilter Avgaspanna Rökgas- kondense- ring
Textilt spärrfilter
Skorsten
Rökgas- fläkt
Vattenbehandling Absorptions-
värmepump
Akti vt kol Kalk Aska
Bottenaska Avfalls-
bunker
Luftinblåsning Rökgasåterföring
Energin i ångan vä xlas till fjärrvärme
Fjärrvärme Pann-
tuber 1000oC
140oC
Avfallsbunker
Fjärrvärme
Returledning Energin i ångan växlas till fjärrvärme
?
Av- gas- panna Kataly- sator Textilt spärr- filter Scrubber
HCl SO2 Kon- densat Elektrofilter
Rökgasåterföring
Ånga ut till kunder
Flygaska
Absorptions- värmepump
Vatten- behandling
Skorsten
Bottenaska För-
brän- nings- luft
Kond.
Gips Avfallsbunker
Fjärrvärme
Returledning Energin i ångan växlas till fjärrvärme
?
Av- gas- panna Kataly- sator Textilt spärr- filter Scrubber
HCl SO2 Kon- densat Elektrofilter
Rökgasåterföring
Ånga ut till kunder
Flygaska
Absorptions- värmepump
Vatten- behandling
Skorsten
Bottenaska För-
brän- nings- luft
Kond.
Gips Kond.
Gips
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The heat from the flue gas is utilized in boilers where feed water is heated to steam with a pressure of approximately 16 bar. When the production of steam exceeds the internal and external demand the steam is either transferred to a steam turbine for electricity and heat production or transferred to heat exchangers that heats the water in the district heating network. The turbine is connected to the main steam circuit at the plant so that the waste blocks and electric boilers can provide steam to it.
An electrostatic precipitator filter is located after each boiler to remove particles from the flue gas. The fly ash is removed from the filters and transported to landfill.
Flue gases from Block 1 and 4 are after the filters combined to a joint flue gas duct, an economizer lower the flue gas temperature to 140 °C and heats the district heating water. In Block 5 the economizer is placed right before the duct leading to the chimney.
Two flue gas condensers are connected in series after the economizer of Block 1 and 4. The flue gas temperature is lowered to 30 °C to condense the water vapor. Approximately two thirds of the flue gas water content are removed, the water is transferred to a water treatment process to remove pollution. The heat removed in the condenser can normally be used in absorption heat pumps. If the capacity of the heat pumps decreases for some reason the cooling effect of condensing decreases. To secure operational temperatures air coolers are used in parallel to the absorption heat pumps. In Block 5 the flue gas condenser is located after two scrubbers that removes HCl and SO2.
Absorption heat pumps are used to utilize low grade heat from the flue gas condensers. Steam is used as a high-temperature energy source for the absorption process where water is the refrigerant and lithium bromide is the absorbent. The energy from the heat pumps is used to heat the district heating return water.
The heat pumps can also be used as chillers for district cooling.
After the flue gas condensers, the flue gas is reheated, to prevent corrosion, before passed through fabric filters that removes particulates. In Block 1 and 4, lime and ash from the electric filter are added to bind with acid gases and organic compounds. In Block 5 activated carbon is added for the same purpose. Lastly, the flue gas is released through the chimney.
HVC: Hetvatten-centralen (HVC) was built in 1985 and is a boiler that produces hot water for district heating. Peat was originally used as fuel; it was also possible to combust fossil oil. In 2018, the boiler was converted to operate on wood pellets primarily. Additionally, bio-oil and fossil oil are possible fuels. The wood pellets are transported from an on-site storage location with a conveyor and fed to a mill before combusting. In the combustor urea is injected to reduce formation of NOx. Air supplied to the combustor is preheated by the flue gas exiting. The flue gas is treated in an electric filter and a fabric filter similar to the waste-to-energy lines. After the filters the flue gas is transferred to the chimney. The process of HVC before it was converted to wood pellets is shown in Figure 7.
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Figure 7 Heat production process of HVC (Vattenfall, 2016)
Carpe Futurum (CF): A steam boiler of the kind bubbling fluidized bed is under construction and it is planned to be in operation in 2021. The fuel will comprise of a mix of biomass, for instance wood chips, forest residue and recycled wood. Two silos will be built for fuel storage with an approximate capacity of three days of full load. The initial boiler will only produce steam for heating purposes, however, the production unit is prepared to be able to integrate a steam turbine for electricity production in the future.
Hot water boilers: there are four additional hot water boilers, H3, H4, H5 and H6. They are used as a back-up to deliver hot water to district heating when there is disruption in production or when district heating demand is too high for the other production units. H3 and H4 are converted to run on bio-oil while H5 and H6 still use fossil oil.
2.3.4 Load factor and future operation
The production in a power plant is operated to meet the demand of customers. In the case of Uppsala different types of thermal energy are the primary products. In general, the production unit with lowest operation cost are in operation as much as possible and production units with higher operation cost are put in operation when demand is increasing. This principle is used when planning the operation for the production units in Uppsala power plant. Figure 8 shows how the production of district heating is planned to develop from 2019 to 2023.
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Figure 8 District heating production 2019-2023 (Padban, 2020).
When integrating CC to a production unit the goal is to remove as much CO2 as possible from the process.
Therefore, it is important to consider how much each production unit will operate. Maximizing the load of the production unit, and thus capture of CO2, will also lead to a faster return on investment. The waste-to- energy units are operating most of the time and will continue to do so in the future. The oil boilers are only operating during the peak hours and will be in operation less frequently in the future. Therefore, they will not be a feasible option for CC retrofitting. HVC is in operation more hours since wood pellets is more cost-effective than bio-oil. CF will be in full operation 2022 and be fuelled by unrefined, cheap biomass and cover the production mainly from an old CHP unit (KVV) that was put out of operation in 2019. During the time of construction of CF, the heat demand will be covered by HVC.
2.3.5 Retrofittability in the Uppsala plant
Carbon capture can either be installed into a new heat and power plant or be retrofitted into an already existing one. In the case of having already existing production units the choice will be to retrofit it or retire it prematurely to build a new one with CC. Table 1 shows the planned year of reconstruction of the production units and also the thermal and electrical effect. Notice that the electrical effect is 10 MW in total for block 1, 4 and 5. This is because only one turbine is connected to utilize steam produced in the waste blocks. The choice of retrofitting is justified if the facility planned lifetime is long enough. All production units are planned to be in operation for at least 20 more years. Considering the lifetime each production unit is still feasible for CC retrofitting. However, refurbishment will be necessary to reach the planned deconstruction year and can complicate the choice of CC technology.
Table 1 Year of reconstruction and effect of the assessed production units, thermal effect includes flue gas condensation
Production unit Block 1, 4 Block 5 HVC CF Year of reconstruction 2040 2045 2043 2060
Effect [MWth] 56+36 92 120 112
Effect [MWel] 10 0 0
2.3.6 Flue gas
The flue gas properties and composition are important factors to consider when deciding what CC technology to use and how to optimize the performance of the process. The goal is to separate CO2 from a stream mainly consisting of N2. Choice of fuel and layout of the power production unit affect the
