scholarly journals Post-combustion slipstream CO2-capture test facility at Jiangyou Power Plant, Sichuan, China: performance of a membrane separation module under dynamic power-plant operations

Clean Energy ◽  
2021 ◽  
Vol 5 (4) ◽  
pp. 742-755
Author(s):  
Qian Cui ◽  
Baodeng Wang ◽  
Xinglei Zhao ◽  
Guoping Zhang ◽  
Zhendong He ◽  
...  
Keyword(s):  
Power Plant ◽  
Host Plant ◽  
Co2 Capture ◽  
Power Plants ◽  
Membrane Separation ◽  
Operating Conditions ◽  
Test Facility ◽  
System Control ◽  
Capital Costs ◽  
Wide Range

Abstract Membrane-based separation technologies have the potential to lower the cost of post-combustion CO2 capture from power-plant flue gases through reduced energy and capital costs relative to conventional solvent approaches. Studies have shown promise under controlled conditions, but there is a need for data on performance and reliability under field conditions. Coal-fired power plants in China operate in a dynamic manner, with increases and decreases in output causing changes in flue-gas composition. In this paper, we describe the first field test of a membrane-based post-combustion CO2-capture system connected to a dynamically operating power plant in China. We report the performance of a Membrane Technology Research, Inc. (MTR) PolarisTM membrane-based capture system over a range of plant operating loads ranging from 54% to 84% and conducted an operational stability test over a 168-h period during which the power plant was operating at an average load of 55%, but ramped as high as 79% and as low as 55%. Our results confirm the ability of a membrane capture system to operate effectively over a wide range of host-plant operating conditions, but also identity several issues related to plant integration, system control and resilience in the face of host-plant upsets that require attention as membrane separation systems move towards commercial use.

Methane Steam Reforming and Metallic Membranes to Capture Carbon Dioxide in Gas Turbine Power Plants

2015 ◽  
Author(s):  
Roberto Carapellucci ◽  
Eric Favre ◽  
Lorena Giordano ◽  
Denis Roizard
Keyword(s):  
Power Plant ◽  
Gas Turbine ◽  
Co2 Capture ◽  
Steam Reforming ◽  
Power Plants ◽  
Membrane Separation ◽  
Preliminary Investigation ◽  
Operating Conditions ◽  
Methane Steam Reforming ◽  
System Components

Pre-combustion CO2 capture is regarded as a promising option to manage greenhouse gas emissions from power generation sector. In this regard, metallic membranes can provide a significant boost in power plants energy performances, due to their infinite hydrogen perm-selectivity and their ability to operate at high pressure and temperature. However, the properly integration of these devices still requires a deep investigation of power plant behavior, in order to detect the mutual interaction between system components, which may impose constraints on their operating conditions. This paper aims to investigate a chemically recuperated gas turbine (CRGT) with pre-combustion CO2 recovery based on hydrogen separation through a metallic membrane. At first, the steam reforming and membrane separation processes are investigated, in order to assess their sensitivity to the variation of the main operating parameters. Then, the CRGT power plant with CO2 capture is analyzed, highlighting the effect of system components interaction on energy and environmental performances. In addition, the study accomplishes a preliminary investigation of the system capability to produce an excess of hydrogen to be used as an energy carrier.

Oxy-Fuel Gas Turbine, Gas Generator and Reheat Combustor Technology Development and Demonstration

2010 ◽  
Author(s):  
Roger Anderson ◽  
Fermin Viteri ◽  
Rebecca Hollis ◽  
Ashley Keating ◽  
Jonathan Shipper ◽  
...  
Keyword(s):  
Power Plant ◽  
Gas Turbine ◽  
Gas Turbines ◽  
Clean Energy ◽  
Test Facility ◽  
Working Fluid ◽  
Capital Costs ◽  
2Nd Generation ◽  
Wide Range ◽  
And Performance

Future fossil-fueled power generation systems will require carbon capture and sequestration to comply with government green house gas regulations. The three prime candidate technologies that capture carbon dioxide (CO2) are pre-combustion, post-combustion and oxy-fuel combustion techniques. Clean Energy Systems, Inc. (CES) has recently demonstrated oxy-fuel technology applicable to gas turbines, gas generators, and reheat combustors at their 50MWth research test facility located near Bakersfield, California. CES, in conjunction with Siemens Energy, Inc. and Florida Turbine Technologies, Inc. (FTT) have been working to develop and demonstrate turbomachinery systems that accommodate the inherent characteristics of oxy-fuel (O-F) working fluids. The team adopted an aggressive, but economical development approach to advance turbine technology towards early product realization; goals include incremental advances in power plant output and efficiency while minimizing capital costs and cost of electricity [1]. Proof-of-concept testing was completed via a 20MWth oxy-fuel combustor at CES’s Kimberlina prototype power plant. Operability and performance limits were explored by burning a variety of fuels, including natural gas and (simulated) synthesis gas, over a wide range of conditions to generate a steam/CO2 working fluid that was used to drive a turbo-generator. Successful demonstration led to the development of first generation zero-emission power plants (ZEPP). Fabrication and preliminary testing of 1st generation ZEPP equipment has been completed at Kimberlina power plant (KPP) including two main system components, a large combustor (170MWth) and a modified aeroderivative turbine (GE J79 turbine). Also, a reheat combustion system is being designed to improve plant efficiency. This will incorporate the combustion cans from the J79 engine, modified to accept the system’s steam/CO2 working fluid. A single-can reheat combustor has been designed and tested to verify the viability and performance of an O-F reheater can. After several successful tests of the 1st generation equipment, development started on 2nd generation power plant systems. In this program, a Siemens SGT-900 gas turbine engine will be modified and utilized in a 200MWe power plant. Like the 1st generation system, the expander section of the engine will be used as an advanced intermediate pressure turbine and the can-annular combustor will be modified into a O-F reheat combustor. Design studies are being performed to define the modifications necessary to adapt the hardware to the thermal and structural demands of a steam/CO2 drive gas including testing to characterize the materials behavior when exposed to the deleterious working environment. The results and challenges of 1st and 2nd generation oxy-fuel power plant system development are presented.

scholarly journals Post-combustion slipstream CO2-capture test facility at Jiangyou Power Plant, Sichuan, China: facility design and validation using 30% wt monoethanolamine (MEA) testing

Clean Energy ◽  
2020 ◽  
Vol 4 (2) ◽  
pp. 107-119
Author(s):  
Baodeng Wang ◽  
Qian Cui ◽  
Guoping Zhang ◽  
Yinhua Long ◽  
Yongwei Sun ◽  
...  
Keyword(s):  
Power Plant ◽  
Co2 Capture ◽  
Power Plants ◽  
Field Data ◽  
Co2 Storage ◽  
Test Facility ◽  
Plant Design ◽  
Future Studies ◽  
The World ◽  
Flexible Operation

Abstract Given the dominant share of coal in China’s energy-generation mix and the fact that >50% of the power plants in the country are currently <15 years old, efforts to significantly reduce China’s CO2 footprint will require the deployment of CO2 capture across at least part of its fleet of coal-fired power plants. CO2-capture technology is reaching commercial maturity, but it is still necessary to adapt the technology to regional conditions, such as power-plant design and flexible operation in the China context. Slipstream facilities provide valuable field data to support the commercialization of CO2 capture. We have built a slipstream facility at Jiangyou power plant in Sichuan that will allow us to explore China-relevant issues, especially flexible operation, over the next few years. We plan to share our results with the broader CO2-capture and CO2-storage (CCS) community to accelerate the deployment of CCS in China. This paper describes the design of the slipstream facility and presents results from our steady-state qualification tests using a well-studied benchmark solvent: 30% wt monoethanolamine (MEA). The results from our MEA tests compare favorably to results reported from other slipstream-test facilities around the world, allowing us to commission our system and establish a reference baseline for future studies.

scholarly journals Using CO2 as a Cooling Fluid for Power Plants: A Novel Approach for CO2 Storage and Utilization

2021 ◽  
Vol 11 (11) ◽  
pp. 4974
Author(s):  
Tran X. Phuoc ◽  
Mehrdad Massoudi
Keyword(s):  
Power Plant ◽  
Power Plants ◽  
Saturated Vapor ◽  
Co2 Storage ◽  
Storage Container ◽  
Cooling Fluid ◽  
Capital Costs ◽  
Dry Air ◽  
Novel Approach ◽  
Power Plant Cooling

To our knowledge, the potential use of CO2 as a heat-transmitting fluid for cooling applications in power plants has not been explored very extensively. In this paper, we conduct a theoretical analysis to explore the use of CO2 as the heat transmission fluid. We evaluate and compare the thermophysical properties of both dry air and CO2 and perform a simple analysis on a steam-condensing device where steam flows through one of the flow paths and the cooling fluid (CO2 or air) is expanded from a high-pressure container and flows through the other. Sample calculations are carried out for a saturated-vapor steam at 0.008 MPa and 41.5 °C with the mass flow rate of 0.01 kg/s. The pressure of the storage container ranges from 1 to 5 MPa, and its temperature is kept at 35 °C. The pressure of the cooling fluid (CO2 or dry air) is set at 0.1 MPa. With air as the heat-removing fluid, the steam exits the condensing device as a vapor-liquid steam of 53% to 10% vapor for the container pressure of 1 to 5 MPa. With CO2 as the heat-removing fluid, the steam exits the device still containing 44% and 7% vapor for the container pressure of 1 MPa and 2 MPa, respectively. For the container pressure of 3 MPa and higher, the steam exits the device as a single-phase saturated liquid. Thus, due to its excellent Joule–Thomson cooling effect and heat capacity, CO2 is a better fluid for power plant cooling applications. The condensing surface area is also estimated, and the results show that when CO2 is used, the condensing surface is 50% to 60% less than that when dry air is used. This leads to significant reductions in the condenser size and the capital costs. A rough estimate of the amount of CO2 that can be stored and utilized is also carried out for a steam power plant which operates with steam with a temperature of 540 °C (813 K) and a pressure of 10 MPa at the turbine inlet and saturated-vapor steam at 0.008 MPa at the turbine outlet. The results indicate that if CO2 is used as a cooling fluid, CO2 emitted from a 1000 MW power plant during a period of 250 days could be stored and utilized.

Energy and Exergy Analyses of a Power Plant With Carbon Dioxide Capture Using Multistage Chemical Looping Combustion

2016 ◽  
Vol 139 (3) ◽  
Author(s):  
Bilal Hassan ◽  
Oghare Victor Ogidiama ◽  
Mohammed N. Khan ◽  
Tariq Shamim
Keyword(s):  
Carbon Dioxide ◽  
Power Plant ◽  
Natural Gas ◽  
Co2 Capture ◽  
Power Plants ◽  
Waste Heat ◽  
Chemical Looping Combustion ◽  
Chemical Looping ◽  
Operating Pressure ◽  
Efficiency Gain

A thermodynamic model and parametric analysis of a natural gas-fired power plant with carbon dioxide (CO2) capture using multistage chemical looping combustion (CLC) are presented. CLC is an innovative concept and an attractive option to capture CO2 with a significantly lower energy penalty than other carbon-capture technologies. The principal idea behind CLC is to split the combustion process into two separate steps (redox reactions) carried out in two separate reactors: an oxidation reaction and a reduction reaction, by introducing a suitable metal oxide which acts as an oxygen carrier (OC) that circulates between the two reactors. In this study, an Aspen Plus model was developed by employing the conservation of mass and energy for all components of the CLC system. In the analysis, equilibrium-based thermodynamic reactions with no OC deactivation were considered. The model was employed to investigate the effect of various key operating parameters such as air, fuel, and OC mass flow rates, operating pressure, and waste heat recovery on the performance of a natural gas-fired power plant with multistage CLC. The results of these parameters on the plant's thermal and exergetic efficiencies are presented. Based on the lower heating value, the analysis shows a thermal efficiency gain of more than 6 percentage points for CLC-integrated natural gas power plants compared to similar power plants with pre- or post-combustion CO2 capture technologies.

Combustion Tuning for a Gas Turbine Power Plant Using Data-Driven and Machine Learning Approach

2021 ◽  
Vol 143 (3) ◽  
Author(s):  
Suhui Li ◽  
Huaxin Zhu ◽  
Min Zhu ◽  
Gang Zhao ◽  
Xiaofeng Wei
Keyword(s):  
Machine Learning ◽  
Power Plant ◽  
Gas Turbine ◽  
Operating Conditions ◽  
Data Driven ◽  
Ann Model ◽  
Promising Alternative ◽  
Combustion Performance ◽  
Wide Range ◽  
Gas Turbine Power Plant

Abstract Conventional physics-based or experimental-based approaches for gas turbine combustion tuning are time consuming and cost intensive. Recent advances in data analytics provide an alternative method. In this paper, we present a cross-disciplinary study on the combustion tuning of an F-class gas turbine that combines machine learning with physics understanding. An artificial-neural-network-based (ANN) model is developed to predict the combustion performance (outputs), including NOx emissions, combustion dynamics, combustor vibrational acceleration, and turbine exhaust temperature. The inputs of the ANN model are identified by analyzing the key operating variables that impact the combustion performance, such as the pilot and the premixed fuel flow, and the inlet guide vane angle. The ANN model is trained by field data from an F-class gas turbine power plant. The trained model is able to describe the combustion performance at an acceptable accuracy in a wide range of operating conditions. In combination with the genetic algorithm, the model is applied to optimize the combustion performance of the gas turbine. Results demonstrate that the data-driven method offers a promising alternative for combustion tuning at a low cost and fast turn-around.

Real-Time Thermodynamic Performance Monitoring and Optimum Thermoeconomic Operation of Power Plants

2011 ◽  
Author(s):  
G. Hariharan ◽  
B. Kosanovic
Keyword(s):  
Linear Programming ◽  
Power Plant ◽  
Real Time ◽  
Power Plants ◽  
Operating Conditions ◽  
Recursive Least Squares ◽  
Time Data ◽  
Real Time Data ◽  
One Step ◽  
Inputs And Outputs

The ability of modern power plant data acquisition systems to provide a continuous real-time data feed can be exploited to carry out interesting research studies. In the first part of this study, real-time data from a power plant is used to carry out a comprehensive heat balance calculation. The calculation involves application of the first law of thermodynamics to each powerhouse component. Stoichiometric combustion principles are applied to calculate emissions from fossil fuel consuming components. Exergy analysis is carried out for all components by the combined application of the first and second laws of thermodynamics. In the second part of this study, techniques from the field of System Identification and Linear Programming are brought together in finding thermoeconomically optimum plant operating conditions one step ahead in time. This is done by first using autoregressive models to make short-term predictions of plant inputs and outputs. Then, parameter estimation using recursive least squares is used to determine the relations between the predicted inputs and outputs. The estimated parameters are used in setting up a linear programming problem which is solved using the simplex method. The end result is knowledge of thermoeconomically optimum plant inputs and outputs one step ahead in time.

Empirical Model of Operating Temperature and Pressure Effect towards Pure and Binary O2/ N2 Gas Permeability in Polysulfone Membrane

2018 ◽  
Vol 777 ◽  
pp. 238-244
Author(s):  
Serene Sow Mun Lock ◽  
Kok Keong Lau ◽  
Irene Sow Mei Lock ◽  
Azmi Mohd Shariff ◽  
Yin Fong Yeong ◽  
...  
Keyword(s):  
Empirical Model ◽  
Membrane Separation ◽  
Gas Permeability ◽  
Economic Assessment ◽  
Operating Conditions ◽  
Effect Of Temperature ◽  
Polysulfone Membrane ◽  
Wide Range ◽  
Temperature And Pressure ◽  
Membrane Permeance

Oxygen (O2) enriched air combustion via adaption of polymeric membranes has been proposed to be a feasible alternative to increase combustion proficiency while minimizing the emission of greenhouse gases into the atmosphere. Nonetheless, majority of techno-economic assessment on the O2 enriched combustion evolving membrane separation process are confined to assumption of constant membrane permeance. In reality, it is well known that membrane permeance is highly dependent upon the temperature and pressure to which it is operated. Therefore, in this work, an empirical model, which includes the effect of temperature and pressure to permeance, has been evaluated based on own experimental work using polysulfone membrane. The empirical model has been further validated with published experimental results. It is found that the model is able to provide an excellent characterization of the membrane permeance across a wide range of operating conditions for both pure and binary gas with determination coefficient of minimally 0.99.

A State-of-the-Art CFD Setup for Axial Compressors: Details and Validation

2020 ◽  
Author(s):  
Lorenzo Cozzi ◽  
Filippo Rubechini ◽  
Andrea Arnone ◽  
Savino Depalo ◽  
Pio Astrua ◽  
...  
Keyword(s):  
Gas Turbines ◽  
Power Plants ◽  
State Of The Art ◽  
Secondary Flows ◽  
Operating Conditions ◽  
Tip Clearance ◽  
Cfd Modelling ◽  
Axial Compressors ◽  
Surge Margin ◽  
Wide Range

Abstract The overall fraction of the power produced by renewable sources in the energy market has significantly increased in recent years. The power output of most of these clean sources is intrinsically variable. At present day and most likely in the upcoming future, due to the lack of inexpensive and reliable large energy storage systems, conventional power plants burning fossil fuels will still be part of the energy horizon. In particular, power generators able to promptly support the grid stability, such as gas turbines, will retain a strategic role. This new energy scenario is pushing gas turbine producers to improve the flexibility of their turbomachines, increasing the need for reliable numerical tools adopted to design and validate the new products also in operating conditions far from the nominal one. Especially when dealing with axial compressors, i.e. machines experiencing intense adverse pressure gradients, complex flow structures and severe secondary flows, CFD modelling of offdesign operation can be a real challenge. In this work, a state-of-the art CFD framework for RANS analysis of axial compressors is presented. The various aspects involved in the whole setup are discussed, including boundary conditions, meshing strategies, mixing planes modelling, tip clearance treatment, shroud leakages and turbulence modelling. Some experiences about the choice of these aspects are provided, derived from a long-date practice on this kind of turbomachines. Numerical results are reported for different full-scale compressors of the Ansaldo Energia fleet, covering a wide range of operating conditions. Furthermore, details about the capability of the setup to predict compressor performance and surge-margin have been added to the work. In particular, the setup surge-margin prediction has been evaluated in an operating condition in which the turbomachine experiences experimental stall. Finally, thanks to several on-field data available at different corrected speeds for operating conditions ranging from minimum to full load, a comprehensive validation of the presented numerical framework is also included in the paper.

System Integration and Techno-Economy Analysis of the IGCC Plant With CO2 Capture: Results of the EU H2-IGCC Project

2015 ◽  
Author(s):  
Mohammad Mansouri Majoumerd ◽  
Mohsen Assadi ◽  
Peter Breuhaus ◽  
Øystein Arild
Keyword(s):  
Co2 Capture ◽  
Capital Investment ◽  
Power Plants ◽  
System Analysis ◽  
Combined Cycle ◽  
Economic Evaluations ◽  
Extensive Literature ◽  
Capital Costs ◽  
Cost Of Electricity ◽  
Plant Components

The overall goal of the European co-financed H2-IGCC project was to provide and demonstrate technical solutions for highly efficient and reliable gas turbine technology in the next generation of integrated gasification combined cycle (IGCC) power plants with CO2 capture suitable for combusting undiluted H2-rich syngas. This paper aims at providing an overview of the main activities performed in the system analysis working group of the H2-IGCC project. These activities included the modeling and integration of different plant components to establish a baseline IGCC configuration, adjustments and modifications of the baseline configuration to reach the selected IGCC configuration, performance analysis of the selected plant, performing techno-economic assessments and finally benchmarking with competing fossil-based power technologies. In this regard, an extensive literature survey was performed, validated models (components and sub-systems) were used, and inputs from industrial partners were incorporated into the models. Accordingly, different plant components have been integrated considering the practical operation of the plant. Moreover, realistic assumptions have been made to reach realistic techno-economic evaluations. The presented results show that the efficiency of the IGCC plant with CO2 capture is 35.7% (lower heating value basis). The results also confirm that the efficiency is reduced by 11.3 percentage points due to the deployment of CO2 capture in the IGCC plant. The specific capital costs for the IGCC plant with capture are estimated to be 2,901 €/(kW net) and the cost of electricity for such a plant is 90 €/MWh. It is also shown that the natural gas combined cycle without CO2 capture requires the lowest capital investment, while the lowest cost of electricity is related to IGCC plant without CO2 capture.

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