Gasification Combined Cycle Power Plant Research Articles

Front End Engineering Design Study for Carbon Capture at a Natural Gas Combined Cycle Power Plant in California

The Electric Power Research Institute (EPRI), California Resources Corporation (CRC), and Fluor Corporation are conducting a Front-End Engineering Design (FEED) study to determine the technical and economic feasibility of a retrofit, post-combustion, carbon capture technology on a commercially operating, natural gas-fired, combined cycle (NGCC) power plant in California. Fluor’s Econamine FG PlusSM (EFG+) process is being designed to capture CO2 from the flue gas produced by CRC’s 550 MWe Elk Hills Power Plant (EHPP), a NGCC unit located in the Elk Hills Oil Field near Tupman, Kern County, California. The design basis is to route about 79% of the flue to Fluor’s EFG+ plant with the remaining 21% vented as normal through the stack. Steam is supplied to the capture plant from a gas-fired package boiler whose flue gas is combined with the EHPP flue gas as it’s routed to the EFG+ process. The EFG+ process then captures 90% of the total combined inlet CO2. Overall, about 4,000 tonne (t) CO2/day will be captured and delivered at 97+ mol% purity and 160 bar pressure for use by CRC for CO2 enhanced oil recovery (EOR) or CO2 storage in nearby reservoirs. CRC is one of the largest oil producers in California (132,000 barrels oil equivalent/day) and is pursuing CO2-EOR to increase oil output from California’s Elk Hills field. EHPP is unique in that CRC owns and operates the NGCC power plant, provides its natural gas fuel supply, uses much of its steam and electrical output, and will use the captured CO2 for either CO2 enhanced oil recovery or CO2 storage. The regulatory and tax incentives at the California State level and at the U.S. Federal level combined with the use of CO2 for enhanced oil recovery by CRC, provide a significant commercial interest in using the captured CO2 for enhanced oil recovery in California’s Elk Hills region. Permitting work around CCS with EOR in Elk Hills was initiated in 2010, including an expansive Monitoring, Reporting and Verification (MRV) plan. Regulatory outreach and execution for the current CCS-EOR project were initiated in early 2018 via direct engagement with multiple state and federal agencies. Assuming the FEED study results are favourable, this project could lead to deployment of one of the world’s largest carbon capture processes on a power plant – coal- or gas-fired.

Adding Energy Storage to the Combined Cycle

Abstract The efficient natural gas Combined Cycle Power Plant (CCPP) has driven a substantial reduction in Greenhouse Gas (GHG) emissions, while gas turbine peaking plants also provide backup for variable renewable resources. As more wind and solar generation is added to grids around the world, there is a need for more flexible CCPPs with faster startup and ramping capability, storage of increasingly over-abundant renewable energy, and lower GHG emissions from dispatchable power plants. Novel integration of energy storage with the CCPP can meet these needs at lower cost than alternatives like batteries.

CO2 Capture by Using a Membrane-absorption Hybrid Process in the Nature Gas Combined Cycle Power Plants

ABSTRACT This study’s main objective was to optimize the design parameters of the hybrid membrane-absorption CO2-capture process in natural gas steam cycle (NGCC) power plants. To calculate the CO2 concentration in the permeating gas and the required area for the separating membrane, a mass transfer model of a membrane for separating CO2, N2 and H2O was developed in Aspen Plus. The effects of the CO2 recovery rate of the membrane, the ratio of the feed gas pressure to the permeating-side gas pressure and the flow rate of the flue gas on the required area for the membrane, the power consumption of the compressor and the heat duty for the solvent regeneration were then analyzed. The optimal feed-gas-to-permeating-side-gas pressure ratio and the flue gas flow rate were found to be 10:1 and 50%, respectively. Furthermore, compared to traditional chemical absorption, the solvent regeneration’s heat duty decreased by more than 20.7% when the gas flow rate and the CO2 recovery rate were 100% and 20%, respectively.

Simulation and economic evaluation of heat and power generation from flare gases in a combined cycle power plant

In recent decades, the release of flare gases from different units of chemical industries into the atmosphere has become a substantial environmental problem all around the world. Therefore, recovery or use of flare gases has become much more critical. Combined heat and power generation from flare gases is one of the most economical methods for recovering flare gases. Two power generator gas cycle power plant or a combined cycle power plant can be used to generate heat and power. In this research, simulation and economic evaluation of heat and power generation from flare gases in a gas cycle power plant and combined cycle power plant using PRO/II v.10 software. Finally, by changing the effective operating parameters such as air to treated flare gas ratio, the outlet pressure of compressors, outlet pressure of steam and gas turbine, outlet pressure of pumps and adiabatic efficiency steam and gas turbine, heat and power generation and total capital and operating cost were investigated and analyzed. The results of simulation and sensitivity analysis showed that the use of flare gas with a mass flow rate of 9700 kg/h (mole fraction of CH4: 0. 84) could be used to construct a combined cycle power plant with a capacity of 115 MW with an investment cost of 100 M$. This value of energy surpasses the need for an average community with 85000 families, and the excess can be sold to the national grid.

Time-Resolved Cost Analysis of Natural Gas Power Plant Conversion to Bioenergy with Carbon Capture and Storage to Support Net-Zero Emissions.

The ongoing construction of natural gas combined cycle (NGCC) power plants is incompatible with a transition to global net-zero greenhouse gas emissions. This work evaluates the emission pricing and technology costs required to convert an existing NGCC power plant to a biomethane-based bioenergy with carbon capture and storage (BECCS) system. The conversion was evaluated using techno-economic analysis and time-resolved life cycle assessment. At current technology costs, carbon dioxide equivalent emission prices of $142 and $215 per metric ton are required to allow a BECCS conversion to compete with normal operation or shutdown, respectively, of an existing NGCC power plant. These results show further technological development must occur in parallel with emission pricing to make BECCS viable. If mid-range emission pricing estimates are implemented ($25-$105 per metric ton), BECCS capital cost targets range from $1434 to $2098 per kW of capacity, while operational costs range from $32 to $51 per MWh of electricity produced to enable conversion. These findings indicate that operational costs associated with fuel consumption and production must be significantly reduced to make a BECCS conversion viable, even with emission pricing. All data and methods of this work have been made publicly available in an open-source model.

The Effect of the Carbon Tax Value on the Optimal Parameters and Characteristics of Coal Power Plants

Abstract The paper investigates the effect of the carbon tax on the optimal parameters and indicators of two coal power plants: a steam turbine power unit with coal dust burning in a steam boiler and an internal gasification combined cycle power plant. Sufficiently detailed mathematical models have been developed for the considered plants that are focused on calculating the flow rates of working fluids and coolants and thermodynamic parameters at all points of the flowcharts, as well as the structural characteristics of the plant elements. The problems of optimizing the parameters of these plants related to the problems of nonlinear mathematical programming are formulated. As an efficiency criterion, the price of electricity is used at given value of the internal rate of return on investment. Optimization calculations were carried out with a carbon tax in the range from 0 $/t to 140 $/t in increments of 20 $/t. It is shown that with an increase in the charge for emissions, the optimal efficiency of the plants increases, as well as the specific investment. Specific CO2 emissions are reduced. Throughout the entire range of carbon tax values, IGCC power plant has the best economic and environmental indicators.

Solar Integrated Unit to Reduce Power and Cooling Penalty of a Natural Gas Combined Cycle Plant integrated with a Carbon Capture System

Integrating solar assisted plant with a carbon capture unit to provide the required reboiler heat duty has been recently investigated extensively to reduce the negative impact of carbon capture unit on plant performance. However, using solar assisted plant to provide the required energy in the reboiler of the stripper leads to increase plant’s condenser duty unfavorably. In the present study, two novel configurations have been proposed for a concentrated solar assisted power plant to generate the required reboiler duty in the stripper of a post-combustion carbon capture unit (PCCC-SAPP) in a (630 MWe) natural gas combined cycle (NGCC) power plant to reduce both the condenser duty and power penalty of the plant simultaneously. In the present study, both the solar plant and plant’s low-pressure steam (LPS) are contributing to deliver the required reboiler thermal energy in the first method while the extraction is from the cooling system load in addition to the solar plant in the second method. Solar contribution factor (SCF) is the main criteria which has been used to evaluate the findings. Condenser duty with its associated water requirements, power penalty, and the required solar field land area are the parameters which have been investigated in the preset study. It has been found that the second configuration method has better impact on the performance of the plant and its associated cooling system than the first configuration method where zero power penalty is consumed in the second configuration as well as reducing the condenser duty with its related water usage amounts. In addition, it was shown that raw water withdrawal and consumption amounts in term of (gal/min)/MWnet decrease with increasing SCF in the first configuration where raw water withdrawal and consumption amounts are 7.23 (gal/min)/MWnet, and 5.17 (gal/min)/MWnet at SCF equals to 0 while these amounts reach to 6.74 (gal/min)/MWnet and 4.82 (gal/min)/MWnet at SCF of 0.95 respectively. On the other hand, these amounts increase with increasing SCF in the second configuration where water withdrawal and consumption values approach 6.75 (gal/min)/MWnet, and 4.92 (gal/min)/MWnet at SCF equals to 0 while the amounts are equal to 7.93 (gal/min)/MWnet and 5.81 (gal/min)/MWnet at SCF equals to 0.95 respectively despite that condenser duty is increasing in the both methods. This comes from the fact that the net produced power is increasing in the first scenario with SCF while it keeps constant in the second scenario. Furthermore, the relationship between the solar field’s required land area and solar direct normal irradiation (DNI) was investigated in the present paper under four different SCF; 0.2, 0.4, 0.6, and 0.8. It was found that reducing the solar field’s required land area requires increase in the DNI and decrease in the SCF where the reboiler heat duty is constant in the PCCC and the relationship is almost exponential. The validation was performed with an American governmental report (NETL, 2015) showing that the presented results has a significant agreement with the report.

Cogasification of Coal and Biomass in an Integrated Gasification Combined Cycle Power Plant: Effects on Thermodynamic Performance and Gas Composition

AbstractTaking inspiration from one of the most significant experiences of coal and biomass cogasification, such as that undertaken in the Willem-Alexander Centrale (WAC) power plant located in Bug...

An improved combined heat and power economic dispatch model for natural gas combined cycle power plants

An increasing number of natural gas combined cycle (NGCC) plants are operated under combined heat and power mode. Therefore, a combined heat and power economic dispatch (CHPED) is the key to achieve the optimal utilization of fuel. In this paper, an improved CHPED model is developed, in which short-term loads variation process models of plants are integrated to ensure the feasibility of dispatched demands. The short-term loads variation process of NGCC plants is modelled based on the power and heat loads control logic in the field operation process. In comparison with the CHPED models in most existing researches, the improved CHPED model can be applied in the real-time field operation of plants. In addition, the influence of heat load ramp rates on CHPED results is investigated, which can offer theoretical support and guidance for field operation. Based on the data from field operation and manufacturer of an NGCC power station, case studies are performed. Results show that the errors between the short-term loads variation process model and field operational data are less than 2.6 s on power load, and less than 1 s on heat load, which proves the accuracy of the model. All the dispatched demands of the improved CHPED model can be met in the required regulation time limits. On one-hour cumulative fuel consumption, the improved CHPED model saves 171.4 kg (0.12%) over the field operational demands. The improved CHPED model not only enhances the economic performance, but also guarantees the operational reliability of plants.

Thermo-economic analyses of isothermal water gas shift reactor integrations into IGCC power plant

Thermodynamic performance and economics of integrating three different types of isothermal water gas shift (WGS) reactors into integrated gasification combined cycle (IGCC) power plants have been analyzed and compared to an IGCC with adiabatic WGS reactors. Isothermal shifting has shown to shift the steam generation from intermediate pressure (IP) steam towards high pressure (HP) steam. More HP steam generation leads to increased power output of the Rankine cycle and ultimately increases efficiency. Another factor impacting the efficiency is the amount of shift steam added to the WGS reactor. By lowering the amount of shift steam needed, more power is generated by the Rankine cycle. Shift steam requirement is reduced at higher temperatures which is favorable for HP steam generation. Integrating an isothermal WGS reactor into an IGCC remains challenging in cases of high carbon capture as thermodynamic equilibrium favors CO conversion at lower temperatures. The relatively low cooling density when HP boiler feedwater is used in the isothermal reactor poses economic challenges as it increases reactor size and catalyst requirement. Using the Ro-number to optimize the isothermal WGS reactor offers the best economic results with reduced capital cost, operating cost and cost of electricity.

Prospect of near-zero-emission IGCC power plants to decarbonize coal-fired power generation in China: Implications from the GreenGen project

An integrated gasification combined cycle (IGCC) power plant with pre-combustion CO2 capture provides a solution to achieve energy security with CO2 emission reduction in China, which has a coal-dominant energy resource structure. This study utilizes the electricity generation and cost information of the GreenGen IGCC plant (265 MW), which is the first and, to date, the only IGCC facility in China, to evaluate the economic performance and competitiveness of this emerging clean coal technology. In the construction stage, the initial investment on the GreenGen plant was approximately $565 million (capital cost: 2133 $/kW; in constant 2017 US dollars). Compared with the US, China incurred significantly lower costs of initial investment for the construction of the IGCC plant, owing to the adoption of a self-developed gasifier. During the operation stage, the levelized cost of electricity (LCOE) without CO2 capture for the GreenGen plant was calculated as 103 $/MWh, whereas it increased to 131 $/MWh with pre-combustion CO2 capture (CO2 capture cost: 42 $/tonne). Currently, an IGCC plant with integrated CO2 capture remains too expensive to be widely used in China. However, simulation results indicate that the LCOE of China’s IGCC plants could be potentially reduced to 80 $/MWh in the future owing to technology innovation, large-scale application and cumulative production. Government policy and financial support to stimulate the research and development of gas turbine and low-rank coal gasification technologies and to subsidize the operation of IGCC plants owing to their environmental benefits would play critical roles in accelerating the development of near-zero-emission IGCC power plants in China.

A high‐efficiency novel IGCC‐OTM carbon capture power plant design

AbstractCoal power plants play an important role in supplying affordable and reliable electricity. It is necessary to develop high‐efficiency and low‐cost carbon capture (CC) technologies to mitigate the associated global warming. Using H2S‐tolerant oxygen transport membranes (OTMs) for hydrogen production and CO2 separation can significantly reduce the energy penalty of CC in integrated gasification combined cycle (IGCC) power plants. We carried out system‐level analysis to investigate a novel IGCC‐CC power plant design using OTMs. We studied the impacts of various operating parameters on the overall efficiency and energy penalty. This novel IGCC‐OTM system has an overall efficiency 3.2%‐point lower than the same system without CC, much lower than the IGCC with water‐gas shift reactors and acid gas removal units (IGCC‐WGS) of 6.8%‐point drop. The specific primary energy consumption for CO2 avoided (SPECCA) of this novel technology is 1.08 MJ kgCO2−1, which is 59.4% lower than that of the IGCC‐WGS.

Dynamic Optimal Dispatch of Energy Systems with Intermittent Renewables and Damage Model

With the increasing penetration of intermittent renewable energy sources into the grid, there is a growing need for process systems-based strategies that integrate dispatchable and variable energy systems for supplying the demand while maintaining grid reliability. The proposed framework corresponds to a dynamic mixed-integer linear programming optimization approach that integrates coal-fired and natural gas-fired power plants, NaS batteries for energy storage, and solar/wind energy to supply the demand. This optimization approach considers an economic goal and constraints to provide power balance while maintaining the overall damage of the natural gas combined cycle (NGCC) power plant drum under a maximum stress as well as avoiding the overheating of the NGCC superheater and reheater. Renewable curtailment levels are also retained at minimum levels. Case studies are analyzed considering different loads and renewable penetration levels. The results show that the demand was met for all cases. Grid flexibility was mostly provided by the NGCC, while the batteries were used sparingly. In addition, considering a CO2 equivalent analysis, the environmental performance was intrinsically connected to grid flexibility and the level of renewable penetration. Stress analysis results reinforced the necessity for an equipment health-related constraint.

A parametric study of process design and cycle configurations for pre-combustion PSA applied to NGCC power plants

Natural gas combined cycle (NGCC) power plants show favourable conditions for the implementation of pressure swing adsorption (PSA) for the capture of carbon dioxide. These plants also show the advantage of a hydrogen co-production system. The challenge when implementing PSA in these plants is to achieve reference configurations that can obtain both products (hydrogen and carbon dioxide) at high purity levels, maximizing the recovery of hydrogen as a valuable product. This study presents the scale-up of a previously reported laboratory-based, four-bed, seven-step PSA model and a parametric study of the scaled-up PSA variables to maximize the product performance parameters. The capacity of the PSA model is based on the flow rate requirements of a GE-10 gas turbine, which can operate with up to 95% hydrogen purity. A parametric study using global system analysis (GSA) showed the effect of the bed diameter, length-to-diameter ratio and purge-to-feed flow rate ratio upon the product performance parameters. A purity of carbon dioxide of 95.37% and a hydrogen recovery of 92.27% was obtained with a purge-to-feed flow rate ratio of 0.22. The purity of hydrogen stayed close to 99.99%, with maximum deviations around 0.0001% for all case studies. The purity of the carbon dioxide and the recovery of hydrogen were further improved by considering additional PSA configurations. The addition of an assisted purge step and three pressure equalization steps improved these performance parameters by two percentage points. Overall, the model with one pressure equalization step, assisted purge step and rinse step after the feed step showed promising results with a purity of carbon dioxide of 98.28% and hydrogen recovery of 95.48%. Lower capitals costs are expected for this configuration, compared to adding pressure equalization steps using more than four fixed-bed units.

Parametric Process Design and Economic Analysis of Post-Combustion CO2 Capture and Compression for Coal- and Natural Gas-Fired Power Plants

For the envisaged large number of commercial-scale carbon capture and storage (CCS) projects that are to be implemented in the near future, a number of issues still need to be resolved, the most prominent being the large capital and operational costs incurred for the CO2 capture and compression process. An economic assessment of the capture and compression system based on optimal design data is important for CCS deployment. In this paper, the parametric process design approach is used to optimally design coal and natural gas monoethanolamine (MEA)-based post-combustion CO2 absorption–desorption capture (PCC) and compression plants that can be integrated into large-scale 550 MW coal-fired and 555 MW natural gas combined cycle (NGCC) power plants, respectively, for capturing CO2 from their flue gases. The study then comparatively assesses the energy performance and economic viabilities of both plants to ascertain their operational feasibilities and relative costs. The parametric processes are presented and discussed. The results indicate that, at 90% CO2 capture efficiency, for the coal PCC plant, with 13.5 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 2.87 kg/kg and CO2 lean loading of 0.2082 mol CO2/mol MEA, the CO2 avoidance cost is about $72/tCO2, and, for the NGCC PCC plant, with 4.04 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 0.98 kg/kg and CO2 lean loading of 0.2307 mol CO2/mol MEA, the CO2 avoidance cost is about $94/tCO2.

High‐performance oxygen transport membrane reactors integrated with IGCC for carbon capture

AbstractPrecombustion carbon capture is an effective strategy to reduce large‐scale CO2 emissions, which is mainly used in the area of integrated gasification combined cycle (IGCC) power plants. Oxygen transport membranes (OTMs) were suggested as the air separation unit to produce high purity oxygen for the gasifier. However, the improvement in efficiency was limited. Here, a new IGCC process is reported based on a robust OTM reactor, where the OTM reactor is used behind the coal gasifier. This IGCC‐OTM process fulfills syngas oxidation, H2 production, and carbon capture in one unit, thus a significant decrease of the energy penalty is expectable. The membrane reactor does not use noble metal components, and exhibits high hydrogen production rates, high hydrogen separation factor (103–104), and stable performance in a gas mixture mimicking real syngas compositions from a coal gasifier with H2S concentrations up to 1,000 ppm.

Sustainable personnel scheduling supported by an artificial neural network model in a natural gas combined cycle power plant

Despite the impact of personnel scheduling on the sustainability of production processes, it is a rarely studied problem in the electricity generation sector, whose main purpose is sustainable energy generation. From this point of view, personnel scheduling problem is handled in this study based on the impact of this problem, which focuses on fair and balanced job distribution according to the personnel qualifications, on the sustainable generation in the power plants. With its advantages such as ease of operation and maintenance, fast commissioning, lower greenhouse gas emissions compared to other fossil fuels and etc. one of the biggest Natural Gas Combined Cycle Power Plant (NGCCPP) in Turkey is chosen as application area. The main purpose of the study is to demonstrate the effect of fair, balanced and competency-based personnel scheduling on generation stoppages resulting from personnel planning in power plants, which have great importance in energy supply security of the countries. This study is the first in the literature in terms of three different aspects. Firstly, in the energy sector, it is different in that it is a personnel scheduling study that takes into consideration the job assignment of the personnel according to their abilities and minimizes costs. Secondly, the large size of the problem is different from that of previous studies in the literature. Finally, the number of personnel employed in this generation facility varies according to the season. At this point, the past generation data are analyzed using an Artificial Neural Network (ANN) method and an estimation is made, and personnel scheduling is performed in the light of this information. Consequently, the proposed multi-objective mathematical model supported with multi-criteria decision making and ANN, shutdown rate of the power plant due to operator error is reduced 67.3%, and personnel satisfaction level is increased from 42% to 89%as solution.

Biofixation of CO2 emissions from natural gas combined cycle power plant

The growing impacts of climate change mainly due to the increasing emissions of GHG, especially carbon dioxide, has led to the development and implementation of specific strategies and policies to reduce them. Carbon capture and utilization (CCU) is currently seen as a good option, as it contributes to reduce the net carbon emissions and fulfil the goals of the Paris Agreement. This work analyses the economic potential of CO2 biofixation by microalgae from the exhaust gas of a Portuguese Natural Gas Combined Cycle (NGCC) power plant. Literature and real operational data are used, collected from reports of Portuguese power generation companies. A preliminary design and economic analysis of the carbon biofixation system was done. Results show that, although requiring a very large investment, the process is economically viable. In further studies a more in depth approach and detailed project combined with a sensitivity analysis, and a comparison with the chemical based CO2 fixation will be done.

Influence of removal efficiency on a moving granular bed filter

High power generation efficiency and environmental performance are obtained in the integrated coal gasification combined cycle (IGCC) power plants. Hot gas clean-up is a key technology in IGCC systems. In this paper, a moving granular bed filter was constructed to examine the effect on collection efficiency when variations in the working parameters, namely, the mass flow rate, the filtration superficial velocity, and the amount of dust particulates at the inlet were introduced. A method to enhance particulate removal was proposed and tested in a lab-scale experiment. In addition, the study analyses the motion of gas flow in the inlet gas device of filter system. The results indicated a low amount of dust in the outlet of filter system when a mass flow rate of 0.008 kg/s and a filtration superficial velocity of 0.42 m/s were used. Furthermore, this new method is suitable for IGCC and other industrial areas involving high-temperature environments.

Fixed and Capture Level Reduction operating modes for carbon dioxide removal in a Natural Gas Combined Cycle power plant

The characteristics (flowrate, composition, CO2 partial pressure) of the flue gas exiting a Natural Gas Combined Cycle (NGCC) power plant are different from the ones of coal-fired units on which analyses in the literature are usually focusing, therefore for application of Carbon Capture and Storage (CCS) to the removal of CO2 from this type of stream a detailed study is needed. This work applies the method of flexible operation aimed at reducing the economic disadvantages of a CCS plant, and considers the Capture Level Reduction (CLR) mode for the carbon dioxide removal section of a NGCC power plant located in Italy, of which type the number of units is constantly increasing. The CLR mode consists in emitting part of the carbon dioxide at given times during the day by bypassing part of the rich solvent and thus reducing the energy requirements for regeneration of the solvent and compression of the removed CO2. For the study a proprietary code developed by the GASP group of Politecnico di Milano, based on real energy prices and demand and taking into account different values of possible carbon taxes, has been employed. The results show that the best load to the absorption section strongly depends on the value of the considered carbon tax, in addition to the time-dependent request and price of electricity. A carbon tax of 5 €/tonCO2 generally does not favor the operation of the CCS system, while higher values exert a more significant influence on the revenues. Carbon taxes of 115 €/tonCO2 for the winter period and of 145 €/tonCO2 for the summer period make the operation of the CCS section more economically advantageous than emitting carbon dioxide to the atmosphere. In any case, also when applied to CO2 removal in power plants fed by natural gas, the CLR mode results more advantageous than fixed operation, thus making power plants companies increasing their efforts in reducing greenhouse gas emissions.