scholarly journals Natural Gas vs. Electricity for Solvent-Based Direct Air Capture

2021 ◽  
Vol 2 ◽  
Author(s):  
Noah McQueen ◽  
Michael J. Desmond ◽  
Robert H. Socolow ◽  
Peter Psarras ◽  
Jennifer Wilcox
Keyword(s):  
Natural Gas ◽  
Energy Systems ◽  
Energy System ◽  
Levelized Cost Of Electricity ◽  
Electricity Cost ◽  
Direct Air Capture ◽  
Air Capture ◽  
Total Capture ◽  
Continuous Power ◽  
The Cost

Removing CO2 from the air with chemicals (Direct Air Capture, DAC) requires a significant amount of energy. Here, we evaluate the cost of co-constructing a solvent DAC process with its energy system. We compare eight energy systems paired with two alternative designs for a liquid-solvent DAC system capturing 1 MtCO2/year, which requires roughly 240 to 300 megawatts of steady power equivalent, 80% thermal and 20% electric. Two energy systems burn natural gas onsite for heat and electricity, capturing nearly all the CO2 released during combustion, and six are all-electric non-fossil systems. The cost of the DAC facility alone contributes $310/tCO2 for a conventional process-based design and $150/tCO2 for a more novel design. When the decomposition of calcium carbonate occurs within a natural-gas-heated calciner, the energy system adds only $80/tCO2 to these costs, assuming $3.25/GJ ($3.43/MMBtu) gas. However, leakage in the natural gas supply chain increases the cost of net capture dramatically: with 2.3% leakage (U.S. national average) and a 20-year Global Warming Potential of 86, costs are about 50% higher. For the all-electric systems, the total capture cost depends on the electricity cost: for each $/MWh of levelized cost of electricity, the total capture cost increases by roughly $2/tCO2. Continuous power is required, because the high-temperature calciner cannot be cycled on and off, so solar and wind power must be supplemented with storage. Our representative capture costs are $250–$440/tCO2 for geothermal energy, $370–$620/tCO2 for nuclear energy (two variants–a light water reactor and small modular nuclear), $360–$570/tCO2 for wind, $430–$690/tCO2 for solar photovoltaics (two variants assuming different daily solar capacities), and $300–$490/tCO2 for a hybrid system with a natural-gas-powered electric calciner.

scholarly journals Post-Combustion Capture or Direct Air Capture in Decarbonizing US Natural Gas Power?

2020 ◽  
Author(s):  
Habib Azarabadi ◽  
Klaus S. Lackner
Keyword(s):  
Natural Gas ◽  
Gas Turbines ◽  
Carbon Capture ◽  
Learning By Doing ◽  
Combined Cycle ◽  
Direct Air Capture ◽  
Natural Gas Combined Cycle ◽  
Air Capture ◽  
The Cost ◽  
The Impact

<p>This analysis investigates the cost of carbon capture from the US natural gas-fired electricity generating fleet comparing two technologies: Post-Combustion Capture and Direct Air Capture (DAC). Many Natural Gas Combined Cycle (NGCC) units are suitable for post-combustion capture. We estimated the cost of post-combustion retrofits and investigated the most important unit characteristics contributing to this cost. Units larger than 350 MW, younger than 15 years, more efficient than 42% and with a utilization (capacity factor) higher than 0.5 are economically retrofittable. Counterintuitively, DAC (which is usually not considered for point-source capture) may be cheaper in addressing emissions from non-retrofittable NGCCs. DAC can also address the residual emissions from retrofitted plants. Moreover, economic challenges of post-combustion capture for small natural gas-fired units with low utilization, such as gas turbines, make DAC look favorable for these units. Considering the cost of post-combustion capture for the entire natural gas-related emissions after incorporating the impact of learning-by-doing for both carbon capture technologies, DAC is the cheaper capture solution for at least 1/3 of all emissions. </p>

Post-Combustion Capture or Direct Air Capture in Decarbonizing US Natural Gas Power?

2020 ◽  
Author(s):  
Habib Azarabadi ◽  
Klaus S. Lackner
Keyword(s):  
Natural Gas ◽  
Gas Turbines ◽  
Carbon Capture ◽  
Learning By Doing ◽  
Combined Cycle ◽  
Direct Air Capture ◽  
Natural Gas Combined Cycle ◽  
Air Capture ◽  
The Cost ◽  
The Impact

<p>This analysis investigates the cost of carbon capture from the US natural gas-fired electricity generating fleet comparing two technologies: Post-Combustion Capture and Direct Air Capture (DAC). Many Natural Gas Combined Cycle (NGCC) units are suitable for post-combustion capture. We estimated the cost of post-combustion retrofits and investigated the most important unit characteristics contributing to this cost. Units larger than 350 MW, younger than 15 years, more efficient than 42% and with a utilization (capacity factor) higher than 0.5 are economically retrofittable. Counterintuitively, DAC (which is usually not considered for point-source capture) may be cheaper in addressing emissions from non-retrofittable NGCCs. DAC can also address the residual emissions from retrofitted plants. Moreover, economic challenges of post-combustion capture for small natural gas-fired units with low utilization, such as gas turbines, make DAC look favorable for these units. Considering the cost of post-combustion capture for the entire natural gas-related emissions after incorporating the impact of learning-by-doing for both carbon capture technologies, DAC is the cheaper capture solution for at least 1/3 of all emissions. </p>

Post-Combustion Capture or Direct Air Capture in Decarbonizing US Natural Gas Power?

2020 ◽  
Author(s):  
Habib Azarabadi ◽  
Klaus S. Lackner
Keyword(s):  
Natural Gas ◽  
Gas Turbines ◽  
Carbon Capture ◽  
Learning By Doing ◽  
Combined Cycle ◽  
Direct Air Capture ◽  
Natural Gas Combined Cycle ◽  
Air Capture ◽  
The Cost ◽  
The Impact

<p>This analysis investigates the cost of carbon capture from the US natural gas-fired electricity generating fleet comparing two technologies: Post-Combustion Capture and Direct Air Capture (DAC). Many Natural Gas Combined Cycle (NGCC) units are suitable for post-combustion capture. We estimated the cost of post-combustion retrofits and investigated the most important unit characteristics contributing to this cost. Units larger than 350 MW, younger than 15 years, more efficient than 42% and with a utilization (capacity factor) higher than 0.5 are economically retrofittable. Counterintuitively, DAC (which is usually not considered for point-source capture) may be cheaper in addressing emissions from non-retrofittable NGCCs. DAC can also address the residual emissions from retrofitted plants. Moreover, economic challenges of post-combustion capture for small natural gas-fired units with low utilization, such as gas turbines, make DAC look favorable for these units. Considering the cost of post-combustion capture for the entire natural gas-related emissions after incorporating the impact of learning-by-doing for both carbon capture technologies, DAC is the cheaper capture solution for at least 1/3 of all emissions. </p>

scholarly journals A methodology for designing decentralised energy systems with predictive control for heat pumps and thermal storage

2019 ◽  
Vol 111 ◽  
pp. 06014
Author(s):  
Andrew Lyden ◽  
Paul Tuohy
Keyword(s):  
Predictive Control ◽  
Thermal Characteristic ◽  
Thermal Characteristics ◽  
Energy Systems ◽  
Thermal Storage ◽  
Energy System ◽  
Heat Pumps ◽  
Hot Water ◽  
Water Tank ◽  
Electricity Cost

Decentralised energy systems provide the potential for adding energy system flexibility by separating demand/supply dynamics with demand side management and storage technologies. They also offer an opportunity for implementing technologies which enable sector coupling benefits, for example, heat pumps with controls set to use excess wind power generation. Gaps in this field relating to planning-level modelling tools have previously been identified: thermal characteristic modelling for thermal storage and advanced options for control. This paper sets out a methodology for modelling decentralised energy systems including heat pumps and thermal storage with the aim of assisting planning-level design. The methodology steps consist of: 1) thermal and electrical demand and local resource assessment methods, 2) energy production models for wind turbines, PV panels, fuel generators, heat pumps, and fuel boilers, 3) bi-directional energy flow models for simple electrical storage, hot water tank thermal storage with thermal characteristics, and a grid-connection, 4) predictive control strategy minimising electricity cost using a 24-hour lookahead, and 5) modelling outputs. Contributions to the identified gaps are examined by analysing the sensible thermal storage model with thermal characteristics and the use of the predictive control. Future extensions and applications of the methodology are discussed.

scholarly journals Daily Operation Optimization of a Hybrid Energy System Considering a Short-Term Electricity Price Forecast Scheme

Energies ◽  
2019 ◽  
Vol 12 (5) ◽  
pp. 924 ◽  
Author(s):  
Pedro Bento ◽  
Hugo Nunes ◽  
José Pombo ◽  
Maria Calado ◽  
Sílvio Mariano
Keyword(s):  
Energy Systems ◽  
Energy System ◽  
Short Term ◽  
Operation Optimization ◽  
Hybrid Energy ◽  
Price Forecast ◽  
Hybrid Energy Systems ◽  
The Cost ◽  
Transportation Electrification ◽  
Installed Capacity

The scenario where the renewable generation penetration is steadily on the rise in an increasingly atomized system, with much of the installed capacity “sitting” on a distribution level, is in clear contrast with the “old paradigm” of a natural oligopoly formed by vertical structures. Thereby, the fading of the classical producer–consumer division to a broader prosumer “concept” is fostered. This crucial transition will tackle environmental harms associated with conventional energy sources, especially in this age where a greater concern regarding sustainability and environmental protection exists. The “smoothness” of this transition from a reliable conventional generation mix to a more volatile and “parti-colored" one will be particularly challenging, given escalating electricity demands arising from transportation electrification and proliferation of demand-response mechanisms. In this foreseeable framework, proper Hybrid Energy Systems sizing, and operation strategies will be crucial to dictate the electric power system’s contribution to the “green” agenda. This paper presents an optimal power dispatch strategy for grid-connected/off-grid hybrid energy systems with storage capabilities. The Short-Term Price Forecast information as an important decision-making tool for market players will guide the cost side dispatch strategy, alongside with the storage availability. Different scenarios were examined to highlight the effectiveness of the proposed approach.

scholarly journals Transition to Sustainability With Natural Gas From Fracking

2014 ◽  
Author(s):  
Kangqian Wu ◽  
Frank Kreith
Keyword(s):  
Natural Gas ◽  
Financial Analysis ◽  
Energy System ◽  
Excess Energy ◽  
Energy Information Administration ◽  
Sustainable System ◽  
Using Data ◽  
The Cost ◽  
Energy Information ◽  
Generation Technology

This paper is an analysis of the energy and money needed to construct a renewable energy system with the excess energy available from natural gas obtained by hydraulic fracturing or “fracking”. Using data from the Energy Information Administration regarding the future availability of natural gas obtained by fracking and the energy required to build a sustainable system consisting of wind power, photo-voltaic energy generation and hydraulic storage, a scenario for the construction of a sustainable system is generated. Finally, a preliminary financial analysis of the cost of the renewable system is made. The analysis demonstrates that it is possible to build a sustainable system from the excess natural gas obtained by fracking in less than 30 years. After that time the energy produced from the renewable system is sufficient to replace those parts of the system that have reached their expected life and construct new sustainable generation technology as required by population growth.

scholarly journals Analyzing the Off-Grid Performance of the Hybrid Photovoltaic/Diesel Energy System for a Peripheral Village

2020 ◽  
Vol 2020 ◽  
pp. 1-15
Author(s):  
Ahmed I. M. Iskanderani ◽  
Ibrahim M. Mehedi ◽  
Makbul A. M. Ramli ◽  
Md. Rafiqul Islam
Keyword(s):  
Renewable Energy ◽  
Optimal Solution ◽  
Energy System ◽  
Rural Electrification ◽  
Diesel Generator ◽  
Rural Villages ◽  
Technoeconomic Analysis ◽  
Electricity Cost ◽  
Viable Solution ◽  
The Cost

Grid extension from the distribution network is being used to meet the demand for rural electricity all over the world. Due to the extra cost of extending electric lines to rural villages, it is not feasible as the installing and commissioning costs are directly related to several constraints such as distance from the main grid, the land location, utilities to be used, and the size of the approximate load. Consequently, it becomes a challenge to apply technoeconomic strategies for rural electrification. Therefore, considering the above issues of rural electrification through grid power, the renewable energy system can be an attractive solution. This research analyzes different types of loads considering domestic, industrial, and agricultural requirements for a remote village in a developing country like Bangladesh. In this paper, four types of demand scenarios are developed considering the income level of inhabitants of the village. The investigation identifies the optimal scope for renewable energy-based electrification and provides a suitable technoeconomic analysis with the help of HOMER software. The obtained results show that a combined architecture containing solar panel, diesel generator, and battery power is a viable solution and economically beneficial. The optimal configuration suggested for the primary scenario consists of 25 kW diesel generators to fulfill the basic demand. The hybrid PV-diesel-battery system becomes the optimal solution while the demand restriction is removed for secondary, tertiary, and full-option scenarios. Commercial and productive loads are considered in the load profile for these three scenarios of supply. For the primary scenario of supply, the electricity cost remains high as $0.449/kWh. On the other hand, the lowest electricity cost ($0.30/kWh) is obtained for the secondary scenario. Although the suggested optimal PV-diesel-battery might not reduce the cost of electricity (COE) and NPC significantly, it is capable to reduce dependency on diesel utilization. Hence, the emission of carbon is reduced due to less utilization of diesel that helps to minimize the greenhouse effect on the environment.

scholarly journals Cost Allocation in Integrated Community Energy Systems—Social Acceptance

2021 ◽  
Vol 13 (17) ◽  
pp. 9951
Author(s):  
Na Li ◽  
Rudi Hakvoort ◽  
Zofia Lukszo
Keyword(s):  
Decision Making ◽  
Local Community ◽  
Social Acceptance ◽  
Cost Allocation ◽  
Energy Systems ◽  
Energy System ◽  
Policy Implications ◽  
Fair Process ◽  
Allocation Method ◽  
The Cost

Integrated community energy systems (ICESs) are a good representative of local energy systems by integrating local distributed energy resources and local communities. It is proposed that costs should be allocated in a socially acceptable manner since there is no regulation in ICESs. In this paper, social acceptance is conceptualized from the dimension of community acceptance considering procedural and distributive justice. A fair process increases the understanding and the acceptance of the cost allocation outcomes, and a fair outcome leads to the acceptance of the cost allocation procedure. This approach adopted the multi-criteria decision-making technique to evaluate social acceptance to select a cost allocation method that was socially acceptable to local community members. The results show that our approach is unique and useful when multiple decision-making groups have to decide together upon the cost allocation method. It is able to provide quantitative results and optimal decisions from a multi-group decision-making perspective. The methodology developed in this research can be applied to any local community energy system to select a cost allocation method. Furthermore, the obtained results can be used by decision-makers to support them in the decision-making process. Based on our approach, policy implications are also analyzed to support the success of cost allocation in ICESs.

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