Optimal heat rejection pressure for transcritical CO2 refrigeration cycle with an expander

Heat rejection pressure plays an important role in designing a transcritical CO₂ refrigeration system, and it has an optimal value to maximize the system’s coefficient of performance (COP). With a thermodynamic simulation model, the optimal heat rejection pressure is studied in the paper for an expander cycle, as well as conventional throttle valve cycle. The effects of compressor efficiency, expander efficiency, gas cooler outlet temperature, and evaporation temperature on the optimal heat rejection pressure are analyzed. It is the first time for a transcritical CO₂ expander cycle that the optimal heat rejection pressure is correlated with the gas cooler outlet temperature and the evaporation temperature at given compressor efficiency and expander efficiency. The average deviation from the correlation to simulation results is less than 1.0%. The correlation provides a guideline to system development and performance optimization of a transcritical CO₂ expander cycle.     

Multi-stage chemical looping combustion (CLC) for combined cycles with CO2 capture

This paper presents application of the chemical looping combustion (CLC) method in natural gas-fired combined cycles for power generation with CO₂ capture. A CLC combined cycle consisting of single CLC-reactor system, an air turbine, a CO₂-turbine and a steam cycle has been designated as the base-case cycle. The base-case cycle can achieve net plant efficiency of about 52% at an oxidation temperature of 1200 °C. In order to achieve a reasonable efficiency at lower oxidation temperatures, reheat is introduced into the air turbine by employing multi CLC-reactors. The results show that the single reheat CLC-combined cycle can achieve net plant efficiency of above 51% at oxidation temperature of 1000 °C and above 53% at the oxidation temperature of 1200 °C including CO₂ compression to 110 bar. The double reheat cycle results in marginal efficiency improvement as compared to the single reheat cycle. The CLC-cycles are also compared with a conventional combined cycle with and without post-combustion capture in amine solution. All the CLC-cycles show higher net plant efficiencies with close to 100% CO₂ capture as compared to a conventional combined cycle with post-combustion capture, which is very promising.     

Off-design performance analysis of a transcritical CO2 Rankine cycle with LNG as cold source

The transcritical CO₂ Rankine cycle with liquefied natural gas (LNG) as cold source is a promising power system to utilize mid- and low-temperature heat source. Most previous works focused on thermodynamic and thermoeconomic analysis or optimization for the system. In this article, an off-design performance analysis for the system is conducted. An off-design mathematical model for the system is established to examine the variation of system performance with the variations of heat source mass flow rate and temperature. A modified sliding pressure regulation control strategy, which regulates turbine inlet pressure to keep the temperature difference between heat source temperature and turbine inlet temperature constant, is applied to control the system when off-design conditions happen. The results show that when the mass flow rate or the temperature of heat source is less or lower than that of design condition, both the net power output of system and the system exergy efficiency decrease, whereas when they are more or higher than the values of design condition, the net power output of system increases but the system exergy efficiency still decreases. In addition, both CO₂ turbine and NG turbine could almost keep the designed efficiency values under the applied control strategy.     

Developing CO2 Emission Parameters to Measure the Environmental Impact on Cooling Applications

This study examines parametric approaches to the calculation of refrigerant-based CO₂ emissions in different cooling areas. Both the exergy analyses of refrigerants, used in domestic, commercial, transportation and industrial applications, and the environmental performances regarding exergetic irreversibility are investigated separately. Then, CO₂ emissions caused by systems are examined via two different parameters, I°) Environmental Impact Factor and ??°) Integrated Impact Factor (CIF). The study is based on a vapor compression cooling cycle model, commonly preferred by cooling applications, and the analyses have been made for 1 kW cooling capacity in relation to evaporator temperatures of the systems. In all cooling application, R134A gas stands out among the others in terms of coefficient of performance and exergy efficiency. Moreover, both emission analyses show that it has the lowest emission value. The paper concludes with an evaluation of the reasons for the refrigerant choice, the design and the selection of such a system, and why exergetic and environmental parameters should be preferred.     

The modelling of a hybrid combined cycle with pressurised fluidised bed combustion and CO2 capture

This study investigates the possibility of capturing CO₂ from flue gas under pressurised conditions, which could prove to be beneficial in comparison to working under atmospheric conditions. Simulations of two hybrid combined cycles with pressurised fluidised bed combustion and CO₂ capture are presented. CO₂ is captured from pressurised flue gas by means of chemical absorption after the boiler but before expansion. The results show a CO₂ capture penalty of approximately 8 percentage points (including 90% CO₂ capture rate and compression to 110 bar), which makes the efficiency for the best performing cycle 43.9%. It is 5.2 percentage points higher than the most probable alternative, i.e. using a natural gas fired combined cycle and a pulverised coal fired condensing plant separately with the same fuel split ratio. The largest part of the penalty is associated with the lower mass flow of flue gas after CO₂ capture, which leads to a decrease in work output in the expander and potential for feed water heating. The penalty caused by the regeneration of absorbent is quite low, since the high pressure permits the use of potassium carbonate, which requires less regeneration heat than for example the more commonly proposed monoethanolamine. Although the efficiencies of the cycles look promising it will be important to perform a cost estimate to be able to make a fair comparison with other systems. Such a cost estimate has not been done in this study. A significant drawback of these hybrid cycles in that respect is the complex nature of the systems that will have a negative effect on the economy.     

CO2 capture from combined cycles integrated with Molten Carbonate Fuel Cells

In this paper Molten Carbonate Fuel Cells (MCFCs) are considered for their potential application in carbon dioxide separation when integrated into natural gas fired combined cycles. The MCFC performs on the anode side an electrochemical oxidation of natural gas by means of CO₃^2? ions which, as far as carbon capture is concerned, results in a twofold advantage: the cell removes CO₂ fed at the cathode to promote carbonate ion transport across the electrolyte and any dilution of the oxidized products is avoided.The MCFC can be “retrofitted” into a combined cycle, giving the opportunity to remove most of the CO₂ contained in the gas turbine exhaust gases before they enter the heat recovery steam generator (HRSG), and allowing to exploit the heat recovery steam cycle in an efficient “hybrid” fuel cell + steam turbine configuration. The carbon dioxide can be easily recovered from the cell anode exhaust after combustion with pure oxygen (supplied by an air separation unit) of the residual fuel, cooling of the combustion products in the HRSG and water separation. The resulting power cycle has the potential to keep the overall cycle electrical efficiency approximately unchanged with respect to the original combined cycle, while separating 80% of the CO₂ otherwise vented and limiting the size of the fuel cell, which contributes to about 17% of the total power output so that most of the power capacity relies on conventional low cost turbo-machinery. The calculated specific energy for CO₂ avoided is about 4 times lower than average values for conventional post-combustion capture technology. A sensitivity analysis shows that positive results hold also changing significantly a number of MCFC and plant design parameters.     

Design and off-design analyses of a pre-combustion CO2 capture process in a natural gas combined cycle power plant

In this study, a cycle designed for capturing the greenhouse gas CO₂ in a natural gas combined cycle power plant has been analyzed. The process is a pre-combustion CO₂ capture cycle utilizing reforming of natural gas and removal of the carbon in the fuel prior to combustion in the gas turbine. The power cycle consists of a H₂-fired gas turbine and a triple pressure steam cycle. Nitrogen is used as fuel diluent and steam is injected into the flame for additional NO_x control. The heat recovery steam generator includes pre-heating for the various process streams. The pre-combustion cycle consists of an air-blown auto-thermal reformer, water–gas shift reactors, an amine absorption system to separate out the CO₂, as well as a CO₂ compression block. Included in the thermodynamic analysis are design calculations, as well as steady-state off-design calculations. Even though the aim is to operate a plant, as the one in this study, at full load there is also a need to be able to operate at part load, meaning off-design analysis is important. A reference case which excludes the pre-combustion cycle and only consists of the power cycle without CO₂ capture was analyzed at both design and off-design conditions for comparison. A high degree of process integration is present in the cycle studied. This can be advantageous from an efficiency stand-point but the complexity of the plant increases. The part load calculations is one way of investigating how flexible the plant is to off-design conditions. In the analysis performed, part load behavior is rather good with efficiency reductions from base load operation comparable to the reference combined cycle plant.     

An investigation of a heat pump system using CO2/propane mixture as a working fluid

In order to decrease the heat rejection pressure of heat pump using pure working fluid, CO₂ or R744, other natural component including hydrocarbons (R290, R600a, R600, R1270, R170, R601) and dimethyl ether (RE170) is added to CO₂, respectively, and then six binary mixtures are achieved. By environmental and thermodynamic comparisons, R290 is selected to be the most appropriate component candidate to mix with CO₂, and meanwhile to weaken the flammability and explosivity for pure R290. Then, the system performances of heat pump using mixture of CO₂ and R290 were experimentally studied when R290 is added to CO₂ with a small fraction, and compared with that of the pure CO₂. The experimental test rig is designed and set up for the transcritical heat pump system. When the refrigerant charge is variable, the heating coefficient performance, optimum heat rejection pressure, compressor power, mass flow rate of refrigerant, and total heat coefficient of gas cooler were researched. The variation ratios of heating coefficient performance and heating capacity with deviation from the optimum refrigerant charge were also investigated. The optimum refrigerant charge of CO₂/R290 is obtained and the research results show that the addition of R290 to CO₂ can efficiently reduce the heat rejection pressure and improve the system performance. The results in the present work could provide useful guidelines for the design and operation of heat pump system using CO₂-based mixture.     

Effective retrofitting of post-combustion CO2 capture to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency

Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO₂ capture plant and associated CO₂ compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO₂ to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.     

Comparative thermodynamic performance analysis of a cascade system for cooling and heating applications

In this study, a comparative thermodynamic performance analysis of cascade system (CCS) for cooling and heating applications is presented and compared for different refrigerant couples. The CCS consists of the low-temperature cycle (LTC) and high-temperature cycle (HTC). The CO₂ was used as working fluid in LTC, whereas the HFE 7000, R134a, R152a, R32, R1234yf, and R365mfc refrigerants were used in HTC. The heating and cooling coefficients of performance (COP_ht, COP_cl) and exergy efficiency of CCS are investigated parametrically according to various factors such as the evaporator, condenser, and reference temperatures. After thermodynamic analyses are completed, the COP_cl of CCS is obtained as 1.802, 1.806, 1.826, 1.769, 1.777, and 1.835 for CO₂-HFE7000, CO₂-R134a, CO₂-R152a, CO₂-R32, CO₂-R1234yf, and CO₂-365mfc refrigerant couples, respectively. Furthermore, the heat exchanger has the highest exergy destruction rate, whereas the expansion valves have the lowest of exergy destruction rate.     

Conceptual design of a three fluidised beds combustion system capturing CO2 with CaO

In this work, the Aspen Hysys conceptual design of a new process for energy generation at large scale with implicit CO₂ capture is presented. This process makes use of the CaO capability for CO₂ capture at high temperature and the possibility of regenerating this sorbent working in interconnected fluidised bed reactors operating at different temperatures. The proposed process has the advantage of producing power with minimum CO₂ emissions and very low energy penalties compared with similar air-based combustion power plants. In this system, five main parts can be distinguished: the combustor where coal is burnt with air, the calciner where the fresh and the recycled CaCO₃ is calcined, the carbonator where the CO₂ produced in the combustor is captured, the supercritical steam cycle and the CO₂ compression system. In this arrangement, the three fluidised bed reactors are interconnected in such a way that it is possible to perform the CaCO₃ calcination at a temperature of 950 °C with the energy transported by a hot solid stream produced in the circulating fluidised bed combustor operating at 1030 °C. The stream rich in CaO produced in the calciner is split into three parts. One of them is transported to the carbonator operating at 650 °C where most of the CO₂ in the flue gas produced in the combustor is captured. The second one is sent to the combustor, where it is heated up and used as energy carrier. The third solid stream that leaves the calciner is a purge in order to maintain the capture system activity and to avoid inert material accumulation. Because of the high temperatures involved in all the system, it is possible to recover most of the energy in the fuel and to produce power in a supercritical steam cycle. A case study is presented and it is demonstrated that under these operating conditions, 90% CO₂ capture efficiency can be achieved with no energy penalty further than the one originated in the CO₂ compression system.     

A solution against well cement degradation under CO2 geological storage environment

Capturing and storing carbon dioxide (CO₂) underground for thousands of years is one way to reduce atmospheric greenhouse gases, often associated with global warming. Leakage through wells is one of the major issues when storing CO₂ in depleted oil or gas reservoirs. CO₂-injection candidates may be new wells, or old wells that are active, closed or abandoned. In all cases, it is critical to ensure that the long-term integrity of the storage wells is not compromised. The loss of well integrity may often be explained by the geochemical alteration of hydrated cement that is used to isolate the annulus across the producing/injection intervals in CO₂-related wells. However, even before any chemical degradation, changes in downhole conditions due to supercritical CO₂ injections can also be responsible for cement debonding from the casing and/or from the formation, leading to rapid CO₂ leakage. A new cement with better CO₂ resistance is compared with conventional cement using experimental procedure and methodology simulating the interaction of set cement with injected, supercritical CO₂ under downhole conditions. Geochemical experimental data and a mechanical modeling approach are presented. The use of adding expanding property to this new cement to avoid microannulus development during the CO₂ injection is discussed.     

Control Issues in the Design of a Gas Turbine Cycle for CO2 Capture

This article is concerned with control issues related to the design of a semi-closed O ₂/CO ₂ gas turbine cycle for CO ₂ capture. Some control strategies and their interaction with the process design are discussed. One control structure is implemented on a dynamic simulation model using a predictive controller, and simulations assess the performance and compare its merits with a conventional PI structure. The results indicate that it can be advantageous for operability to allow a varying (as opposed to fixed) compressor inlet pressure, at the cost of a more expensive design. Furthermore, the results show that a predictive controller has some advantages with respect to the simpler conventional PI control structure, in particular in terms of constraint handling.     

Analytical solution for estimating storage efficiency of geologic sequestration of CO2

During injection of carbon dioxide (CO₂) into deep saline aquifers, the available pore volume of the aquifer may be used inefficiently, thereby decreasing the effective capacity of the repository for CO₂ storage. Storage efficiency is the fraction of the available pore space that is utilized for CO₂ storage, or, in other words, it is the ratio between the volume of stored CO₂ and the maximum available pore volume. In this note, we derive and present simple analytical expressions for estimating CO₂ storage efficiency under the scenario of a constant-rate injection of CO₂ into a confined, homogeneous, isotropic, saline aquifer. The expressions for storage efficiency are derived from models developed previously by other researchers describing the shape of the CO₂-brine interface. The storage efficiency of CO₂ is found to depend on three dimensionless groups, namely: (1) the residual saturation of brine after displacement by CO₂; (2) the ratio of CO₂ mobility to brine mobility; (3) a dimensionless group (which we call a “gravity factor”) that quantifies the importance of CO₂ buoyancy relative to CO₂ injection rate. In the particular case of negligible residual brine saturation and negligible buoyancy effects, the storage efficiency is approximately equal to the ratio of the CO₂ viscosity to the brine viscosity. Storage efficiency decreases as the gravity factor increases, because the buoyancy of the CO₂ causes it to occupy a thin layer at the top of the confined formation, while leaving the lower part of the aquifer under-utilized. Estimates of storage efficiency from our simple analytical expressions are in reasonable agreement with values calculated from simulations performed with more complicated multi-phase-flow simulation software. Therefore, we suggest that the analytical expressions presented herein could be used as a simple and rapid tool to screen the technical or economic feasibility of a proposed CO₂ injection scenario.     

Integration and evaluation of a power plant with a CaO-based CO2 capture system

This paper explores the integration and evaluation of a power plant with a CaO-based CO₂ capture system. There is a great amount of recoverable heat in the CaO-based CO₂ capture process. Five cases for the possible integration of a 600 MW power plant with CaO-based CO₂ capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8 MW but also results in the system with the lowest net power output of 446 MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400 MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846 MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3 €/MWh and the lowest cost of CO₂ avoided of 28.9 €/tCO₂. This new built steam cycle will not affect the operation of the reference plant which vents its CO₂ to the atmosphere, highly reducing the connection between the CO₂ capture process and the reference plant which vents its CO₂ to the atmosphere. The average cost of electricity and the cost of CO₂ avoided of the five cases are about 58.9 €/kWh and 35.9 €/tCO₂, respectively.     

Toward a CO2 zero emissions energy system in the Middle East region

Climate change and energy security are global challenges requiring concerted attention and action by all of the world’s countries. Under these conditions, energy supplier and exporter countries in the Middle East region are experiencing further challenges, such as increasing domestic energy demand while energy exports have to concurrently be kept at high levels. Middle East countries process the largest proven oil and gas reserves in the world and contribute a large fraction of the world’s CO₂ emissions from the use of these as fuels both domestically and internationally. This paper addresses different policies that could dramatically change the future course of the Middle East region toward a zero CO₂ emission energy system. To this aim, an integrated energy supply–demand model has been developed to analyze required commitments including renewable energy and energy efficiency targets and the potential of nuclear power, all of which should need to be considered in order to reduce CO₂ emissions by 2100. The results indicate that nearly 43% of the global energy of the Middle East region can be supplied from non-fossil fuel resources in 2100.     

CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

In this work the feasibility of a CO₂ capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO₂ capture is modelled to study the feasibility of combined heat and power plant for CO₂ capture.Environmental friendly sodium carbonate would be an interesting chemical for CO₂ capture. Sodium carbonate absorbs CO₂ forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO₂ which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO₂.Combined heat and power plants seem to be attractive for CO₂ capture because of the high total energy efficiency of the plants. In a condensing power plant the CO₂ capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.     

Permanent shallow subsoil CO2 flux chambers for monitoring of onshore CO2 geological storage sites

Public concern over the possibility of migration of stored CO₂ to the surface with resulting damage to vegetation or hazard to humans and animals is a matter which will need to be addressed to be able to satisfy likely regulatory requirements for onshore CO₂ storage in a number of jurisdictions. While soil CO₂ concentration is readily measured continuously and in situ with current technology, the measurement of CO₂ flux at depths below the soil A horizon may be a more sensitive and meaningful technique for early detection of a near surface CO₂ plume. We describe a system for the continuous measurement of soil CO₂ flux at a depth of approximately 1.3 m and present results from three instruments deployed at the Otway Basin Pilot Project in Victoria, Australia and one development system deployed at Sutton, near the Australian Capital Canberra.