Natural Gas Combined Cycle Power Research Articles

Technoeconomic evaluation of combined rich and lean vapour compression configuration for CO2 capture from a cement plant

A combined rich and lean vapour compression configuration was investigated for CO2 capture from a cement plant. This was to assess its performance in energy consumption, actual CO2 emission reduction, and cost reduction potentials compared with the conventional process and the simple rich vapour compression and lean vapour compression configurations. Two electricity supply scenarios were considered: from natural gas combined cycle power plant and a renewable source like hydropower. The three vapour compression configurations outperformed the standard CO2 absorption configuration in energy requirement, actual CO2 emissions reduction and in CO2 avoided cost reduction. The best performance was achieved by the combined rich and lean vapour compression configuration. The reboiler heat, equivalent heat and CO2 avoided cost reduction performance was 24 – 30 %, 16 -18 % and 13 – 16 % respectively. However, the performances in energy, CO2 emissions reduction and CO2 avoided cost are only marginally better than the lean vapour compression configuration. The use of renewable electricity, like hydropower electricity will help CO2 capture processes to achieve higher CO2 emission reduction and lower CO2 avoided cost compared to fossil fuel based electricity.

Thermodynamic and economic analyses of natural gas combined cycle power plants with and without the presence of organic Rankine cycle

This study performs the simulation and energy, exergy, and economic analyses of an organic Rankine cycle (ORC) integrated with a natural gas combined cycle. Working fluids studied in this research are ammonia, isobutane, R-11, R-113, and R-141b. The power plant and ORC are simulated using Aspen HYSYS software. The results show that using the ORC leads to an improvement in the thermo-economic indexes of the combined cycle power plant. The sensitivity analysis also demonstrated that using ammonia and isobutane as working fluids results in the highest exergy destruction and the lowest exergy and energy efficiencies; therefore, they are unsuitable. On the other hand, a comparison of thermo-economic results illustrated that among the studied working fluids, R-113 is the desirable selection. According to the simulation, it is deduced that employing R-113 working fluid leads to the net power generation of the plant increasing by 2.48%, the cost of electricity decreasing by 10.75%, and the total energy efficiency of the power plant increasing by 6.02%.

Environmental and Economic Analysis of a Natural Gas Combined Cycle Power Plant Using CO2 Utilization Technologies and Ecosystem Services

Power plants are major contributors to CO2 emissions. Post-combustion carbon capture (PCC) processes are commonly integrated, but the capture effectiveness is limited. In this work, four conversion technologies for CO2 utilization from a power plant plus PCC to produce formic acid, methanol, and syngas as value-added chemicals are analyzed. We also analyze the implications of implementing forest ecosystems, for which trees with three types of maturity are considered. The results show that the environmental implications of process utilization technologies may lack desired effectiveness, since the emissions of the utilization plant may still be significant with respect to the amount of captured CO2. Ecological systems are more effective from environmental considerations, but the number of trees and land use may be too high to process the amount of CO2 produced by power plants. A hybrid scheme that integrates a suitable transformation technology with forest ecosystems shows that they may have benefits from both economic and sustainability considerations.

Techno-Economic Assessment of Natural Gas Combined Cycle Power Plants with Carbon Capture and Utilization

Techno-Economic Assessment of Natural Gas Combined Cycle Power Plants with Carbon Capture and Utilization

Concept design, parameter analysis, and thermodynamic evaluation of a novel integrated gasification chemical-looping combustion combined cycle power generation system

Integrated gasification chemical-looping combustion (IGCLC) is a potential combustion technology with innate CO2 separation for solid fuels. Coupling this technology with coal-fired power plants is expected to greatly alleviate the high efficiency penalty induced by CO2 capture. This study proposes an innovative system called integrated gasification CLC combined cycle (IGCLCCC) that highly integrates a gasification system, a CLC system, a combined cycle, an ultra-supercritical steam cycle, and a CO2 capture system. In the proposed system, the oxygen-depleted stream from air reactor and flue gas from fuel reactor enter the combined cycle and ultra-supercritical steam cycle, respectively, for power generation. The energy and mass balances of the proposed system are determined by process simulation. The relationship between the performance of subsystems and system efficiency is studied by parameter analysis. Results indicate that the net efficiency penalty (0.3 percentage points) of the proposed system is 4.3 to 13.2 percentage points less than those of the conventional CO2 capture power plants, and the power consumption of specific CO2 capture is minimized to 8.3 kWeh/t. Besides, its net efficiency is as high as 45.0%, which is comparable to that of the natural gas combined cycle power plant with a 90% CO2 capture rate. This work provides a new sight into the design of the low-carbon and efficient power generation system.

Life Cycle Environmental Impacts Assessment of Post-Combustion Carbon Capture for Natural Gas Combined Cycle Power Plant in Iraq, Considering Grassroots and Retrofit Design

In this work, the Life Cycle Assessment (LCA) methodology is used to examine the implications of CO2 capture from a natural gas combined cycle power plant with post-combustion carbon capture (NGCC-CCS) in Iraq, taking into account two different design scenarios. In the first scenario (retrofit), the carbon capture unit is considered as an end pipe technology that can be linked to an existing power plant. The second scenario considers a grassroots design, in which a new power plant equipped with a carbon capture unit needs to be constructed. The LCA is carried out based on different impact assessment (LCIA) methodologies of ReCipe 2016 Midpoint (H), TRACI 2.1, and IMPACT 2002+ to investigate whether the chosen LCIA method influences the LCA scenario analysis for decision support in process development. The results of three impact categories applied to both scenarios reveal a 28% reduction in Global Warming Potentials (GWPs) and a 14% and 17% increase in the Particulate Matter Formation Potential (PMFP) and Acidification (AP) potential in the grassroots scenario, respectively. Finally, an uncertainty analysis is performed to more accurately reflect the influence of uncertain factors on the statistical significance of the environmental impact evaluation in this research, indicating that these uncertainties may significantly affect the ultimate decision.

Special issue on “Optimal design and operation of energy systems”

Special issue on “Optimal design and operation of energy systems”

Novel cryogenic carbon dioxide capture and storage process using LNG cold energy in a natural gas combined cycle power plant

This study proposes a novel cryogenic CO2 capture and storage (CCS) process using liquefied natural gas (LNG) cold energy in a natural gas combined cycle (NGCC) power plant. This study makes two major contributions to the literature. First, the cryogenic solid-phase CCS process using LNG cold energy can effectively reduce the efficiency penalty in NGCC power plants by solving the fundamental problems associated with the conventional CCS process: energy-intensive thermal treatment of the monoethanolamine-based absorption process and significant power consumption for compressing CO2 to 150 bar. Second, the cryogenic CCS process requires minimal equipment installation in the NGCC power plant by integrating LNG cold energy utilization and CO2 capture processes. The proposed cryogenic CCS process reduces the efficiency penalty from 14.34 % to 3.51 %, with a 99.93 % CO2 capture rate. We believe this study will provide a novel guideline for reducing the efficiency penalty by overcoming the challenges of the conventional CCS process.

Exploration of optimal operating conditions for a natural gas combined-cycle power plant integrated with post-combustion CO2 capture using 2-amino-2-methyl-1-propanol/piperazine considering the propagation effect

Integrating post-combustion CO2 capture (PCC) into thermal power plants can reduce CO2 emissions but results in a significant decrease in net thermal efficiency. Optimizing PCC operating conditions, such as the ratio of the liquid flow rate to the gas flow rate (L/G) and stripper bottom temperature, reduces the net efficiency penalty. However, previous studies partially neglected the propagation effects of altered operating conditions on process performance, such as the effect of altered L/G and resultant change in fluid velocity on the heat transfer and pressure drop in the rich and lean solution heat exchanger. This study simulated amine-based PCC integrated into a natural gas combined cycle and explored optimal operating conditions comprehensively considering the propagation effects. The net efficiency penalty was minimized to 6.02%-pts. at a stripper bottom temperature of 130 °C and L/G of 0.82 for PCC operation with CO2 compression. Meanwhile, neglecting propagation effects of altered L/G led to underestimation of the efficiency penalty and erroneous determination of optimal operating conditions. The system evaluation methods suggested in this paper contribute to correctly optimizing PCC operating conditions and can be broadly applied to amine-based PCC studies employing novel amine solutions or process modifications.

A novel cryogenic technology for low-cost carbon capture from NGCC power plants for climate change mitigation

To reduce the high cost and water consumption of carbon capture, we present a novel low-cost carbon capture technology (NLCCT). It includes the generation of a cold nitrogen refrigerant (CNR) using minimum energy. The flow rate and temperature (−102 °C to −175 °C) are controlled with a fairly high coefficient of performance, COP. NLCCT uses a novel technique and regenerative cooling and an efficiently structured pre-cooler and a final cooler. This effectively uses the least amount of the CNR to cool the entire flue gas 10 °C to 15 °C below the thermodynamic de-sublimation temperature of CO2. Thus, 99 % of the original CO2 mass fraction in the flue gas de-sublimates and is captured. Detailed thermodynamic modelling shows that NLCCT can capture 99 % of the CO2 from natural gas combined cycle power plants with energy of 631 MJ/tCO2 and water consumption of 574 L/tCO2, and hence with a cost of about $12/tCO2 excluding labor and maintenance. We study the impact of the processing parameters and discuss how to optimise the capture processes to reduce the energy and water consumption further, for the implementation of NLCCT for climate change mitigation at a low cost.

Advanced bibliometric analysis on the coupling of energetic dark greenhouse with natural gas combined cycle power plant for CO2 capture

Advanced bibliometric analysis on the coupling of energetic dark greenhouse with natural gas combined cycle power plant for CO2 capture

Economic viability of using thermal energy storage for flexible carbon capture on natural gas power plants

Fossil fuel-based power plants generate 80 % of the electricity in the United States and provide a reliable generation source for both base and peak power demands. These plants are expected to adapt to changes in environmental policies that will require carbon management with carbon capture and storage (CCS) representing a possible solution. Current solvent-based CCS has a detrimental impact on a power plant's performance due to large heat loads required for carbon capture solvent regeneration. This parasitic load restricts the power plant's output and operation flexibility. Therefore, this study evaluates the feasibility of using thermal storage technologies for natural gas combined cycle (NGCC) power plants coupled with CCS to minimize the impact of solvent regeneration and enable the plant to operate at peak power output. Thermal storage can minimize the impact of CCS on the power plant by providing the heat load required for solvent regeneration during times of peak demand which will allow the plant to operate unrestricted and at full power. In total, fifteen unique thermal storage configurations were evaluated from three thermal storage categories: Brayton cycle heat pump, vapor compression heat pump, and heat recovery steam generator steam extraction for storage. The viability of these systems was determined by evaluating each configuration on thousands of real-world Locational Marginal Pricing (LMP) profiles from the New York Independent System Operator and California Independent System Operator electricity markets using a techno-economic analysis. Results were compared to the performance of a base power plant (NGCC with CCS and no thermal storage) to determine the impact of thermal storage on power plant economics. Overall, six of the thermal storage configurations performed better than base CCS enabled power plant on between 11.5 % and 38.7 % of the LMP signals evaluated. The best performing configuration was a vapor compression heat pump that used flue gas as the working fluid and had both hot and cold thermal storage units. This configuration performed better than the base CCS power plant on 38.7 % of the LMP profiles. The results of this study show thermal storage can mitigate the economic impact of carbon capture solvent regeneration on NGCC power plants. Discussion focuses on the impact of electricity pricing on the optimal thermal storage system, the advantages and disadvantages of the systems evaluated, and identifies limitations with the study.

Uncertainty of the life cycle assessment of biogas power

The main goal of this study was to compare energy consumption scenarios at a small-scale barn with an in situ biogas plant. Five life cycle assessment scenarios of dairy manure management were assessed. A real small-scale manure biogas power plant in Mexico (S-BPP) was used as case study. Five scenarios were modeled: (1.1) electricity consumption from the national grid; (1.2) electricity consumption considering a natural gas combined cycle power plant (CCPP); (2.1) partial use of electricity from the national grid and the electricity produced by the S-BPP; (2.2) partial use of electricity from the CCPP and the S-BPP, and (3) a dry anaerobic digestion S-BPP. A Monte Carlo simulation was carried out to manage the uncertainty with 95 % of confidence. A reduction of emissions in the combined cycle power grid by exploiting the manure to produce biogas, was established. Specifically, in the climate change category, there is an impact reduction by up to 70 %, which corroborates that the choice of small-scale biogas in agriculture systems is environmentally feasible. It is confirmed that using S-BPP produces a significant decrease of impacts when compared to CCPP. The results of the modeling scenarios, such as dry anaerobic digestion and/or combined cycle power plants, show a significant reduction in the emissions of the selected impact categories. This study confirms the need to develop more accurate databases of life cycle inventories regarding the Mexican electricity grid, in order to perform more reliable studies.

Techno-economic comparison of optimized natural gas combined cycle power plants with CO2 capture

Natural gas combined cycle (NGCC) power plants account for a large share of the global energy market. Although many alternative layouts of NGCC plants have already been addressed in the scientific literature, there are still relevant gaps of knowledge in comparative techno-economic performances of the previously proposed alternatives. This article presents a comprehensive comparative study of 19 alternative NGCC power plants with pre-combustion, post-combustion or oxy-fuel combustion CO2 capture processes involving different choices of CO2 absorbents and organic Rankine cycles for energy savings. The purpose of this study is to shed light on comparative techno-economic performances of power plants with different CO2 capture strategies and various organic Rankine cycle configurations. First, performance of each alternative was optimized from a technical (equivalent work) standpoint. Then, the economic performance of each optimized alternative was evaluated. Based on the results within the sample of NGCC plants, using activated methyldiethanolamine could lead to better technical and economic performances than monoethanolamine in pre- and post-combustion capture systems. Moreover, the efficacy of organic Rankine cycles for enhancing the technical and economic performance of NGCC plants with CO2 capture was shown, with a reduction of up to 1.39 years in the payback period for various process configurations.

Scalable Formation of Diamine-Appended Metal–Organic Framework Hollow Fiber Sorbents for Postcombustion CO2 Capture

We describe a straightforward and scalable fabrication of diamine-appended metal–organic framework (MOF)/polymer composite hollow fiber sorbent modules for CO2 capture from dilute streams, such as flue gas from natural gas combined cycle (NGCC) power plants. A specific Mg-MOF, Mg2(dobpdc) (dobpdc4– = 4,4′-dioxidobiphenyl-3,3′-dicarboxylate), incorporated into poly(ether sulfone) (PES) is directly spun through a conventional “dry-jet, wet-quench” method. After phase separation, a cyclic diamine 2-(aminomethyl)piperidine (2-ampd) is infused into the MOF within the polymer matrix during postspinning solvent exchange. The MOF hollow fibers from direct spinning contain as high as 70% MOF in the total fibers with 98% of the pure MOF uptake. The resulting fibers exhibit a step isotherm and a “shock-wave-shock” breakthrough profile consistent with pure 2-ampd-Mg2(dobpdc). This work demonstrates a practical method for fabricating 2-ampd-Mg2(dobpdc) fiber sorbents that display the MOF’s high CO2 adsorption capacity while lowering the pressure drop during operation.

Modeling the operational flexibility of natural gas combined cycle power plants coupled with flexible carbon capture and storage via solvent storage and flexible regeneration

In electricity systems with high shares of variable renewable energy resources, the capability to flexible alter power output can increase the economic value of natural gas combined cycle (NGCC) power plants equipped with carbon capture and sequestration (CCS) and enhance their competitiveness as firm low-carbon resources. Here we examine NGCC power plants w/CCS (NGCC-CCS) coupled with solvent storage to enable flexible operation. We present a modular and detailed modeling formulation to represent these systems in a computationally efficient and accurate manner and to evaluate the operating patterns and system value of flexible CCS designs. The proposed framework breaks down NGCC-CCS plants into major subcomponents and uses linear constraint formulations to enforce energy and mass balances. In addition, thermal power plants are subjected to unit commitment (UC) constraints that are generally time-consuming to solve via conventional methods, which use binary decision variables for start-up and shut-down decisions. We thereby investigate whether the linear relaxation of discrete UC decision variables coupled with a generator clustering method are applicable to model flexible CCS subcomponents. Finally, we integrate this novel flexible CCS formulation into a power system unit commitment and economic dispatch model to present a case study that shows the hourly operating patterns of NGCC-CCS subcomponents and impacts on power system environmental and economic performance. As compared to a conventional binary UC formulation, our results show that linear relaxation of a generator clustering formulation has much faster runtime (18–527 times faster), with errors of 0.01%-3.4% across all the evaluated metrics. The operating patterns and system performance suggest our modeling framework can accurately and tractably capture both plant-level and system-level outcomes. Finally, our results demonstrate that flexible NGCC-CCS systems decrease power system operating costs by increasing power output during peak demand periods to displace higher marginal cost units. We also demonstrate that the system-level benefits provided by flexible operation of NGCC-CCS plants will be increasingly valuable to the future grids with high penetration of variable renewable resources.

Exergetic Analysis of DME Synthesis from CO2 and Renewable Hydrogen

Carbon Capture and Utilization (CCU) is a viable solution to valorise the CO2 captured from industrial plants’ flue gas, thus avoiding emitting it and synthesizing products with high added value. On the other hand, using CO2 as a reactant in chemical processes is a challenging task, and a rigorous analysis of the performance is needed to evaluate the real impact of CCU technologies in terms of efficiency and environmental footprint. In this paper, the energetic performance of a DME and methanol synthesis process fed by 25% of the CO2 captured from a natural gas combined cycle (NGCC) power plant and by the green hydrogen produced through an electrolyser was evaluated. The remaining 75% of the CO2 was compressed and stored underground. The process was assessed by means of an exergetic analysis and compared to post-combustion Carbon Capture and Storage (CCS), where 100% of the CO2 captured was stored underground. Through the exergy analysis, the quality degradation of energy was quantified, and the sources of irreversibility were detected. The carbon-emitting source was a 189 MW Brayton–Joule power plant, which was mainly responsible for exergy destruction. The CCU configuration showed a higher exergy efficiency than the CCS, but higher exergy destruction per non-emitted carbon dioxide. In the DME/methanol production plant, the main contribution to exergy destruction was given by the distillation column separating the reactor outlet stream and, in particular, the top-stage condenser was found to be the component with the highest irreversibility (45% of the total). Additionally, the methanol/DME synthesis reactor destroyed a significant amount of exergy (24%). Globally, DME/methanol synthesis from CO2 and green hydrogen is feasible from an exergetic point of view, with 2.276 MJ of energy gained per 1 MJ of exergy destroyed.

A machine learning-based process operability framework using Gaussian processes

The objective in this work is to develop a machine learning-based framework for process operability using surrogate responses based on Kriging (also known as Gaussian Process Regression). Currently, the available operability approaches for nonlinear systems are limited by the problem dimensionality that they can address, not being computationally tractable for high-dimensional systems. The proposed approach will use Kriging-based models to substitute the developed first-principles or process simulation-based models. The built surrogate models can generate responses that are comparable to the first-principles nonlinear models in terms of accuracy, while reducing the computational effort. To achieve this goal, a framework for the systematic analysis of highly nonlinear, large-dimensional systems at steady state is developed. The proposed approach is benchmarked against current operability methods and provides a new direction in the process operability field employing Kriging models. Two case studies associated with natural/shale gas conversion are addressed to illustrate the effectiveness of the proposed methods, namely a membrane reactor for direct methane conversion to fuels and chemicals and a natural gas combined cycle power plant. It is shown that the computational time for operability calculations is significantly decreased when using the developed approach, with reductions of up to four orders of magnitude, while the relative errors with respect to the output responses is below 0.3% for the worst-case scenario considering all cases. This work thus contributes to machine learning formulations and algorithms for process operability to enable the improved design, operations and manufacturing of chemical and energy systems.

Life cycle assessment shows that retrofitting coal-fired power plants with fuel cells will substantially reduce greenhouse gas emissions

Life cycle assessment shows that retrofitting coal-fired power plants with fuel cells will substantially reduce greenhouse gas emissions

Process design of the piperazine advanced stripper for a 460 MW NGCC

The Texas Carbon Management Program is conducting a Front-End Engineering Design (FEED) for Piperazine with the Advanced Stripper™ (PZAS™) at a natural gas combined cycle power plant in west Texas. This paper presents the design of the advanced stripper system with an emphasis on the selection of packing type, packing height, column diameter, and heat exchanger size, demonstrates the effect of ambient temperature swing on the regeneration energy requirement, and investigates two alternate process configurations that provide better energy performance than PZAS™. The design uses 2 stripper trains, and each train uses two cold cross exchangers, one hot cross exchanger, a stripper column, a CO2 exchanger, and a condenser. Each column consists of two sections of random packing with RSR 2 packing at the top and RSR 3 packing at the bottom, with a total packed height of 7.5 m. The cold exchanger was designed with an NTU of 6, the hot exchanger with an NTU of 2, and the CO2 exchanger with an NTU of 5. At 0.4 rich loading and 0.2 lean loading, this design resulted in a heat duty of 2.85 GJ/tonne CO2. The heat duty can vary up to 3.1 GJ/tonne CO2 due to lower rich loading at higher summer temperature, but the absolute steam requirement is 8–15% lower in the summer.An alternate design, PZAS with hot rich bypass, is proposed, which can reduce the equivalent work of stripping by 1.5–3.5% compared to PZAS at low heat exchanger size, due to a reduction in stripper driving force. Using a hot rich bypass increases the vapor fraction of the total rich bypass stream from 0.3 to 1 mol% compared to using the warm rich bypass, which also contributes to a reduction in lost work in the column. PZAS with hot rich bypass outperforms PZAS in energy requirement below a packing height of 15 m, but fails to do so above 15 m of packing due to a column pinch that results in little change in LMTD of the column. PZAS with hot rich bypass has the potential to minimize capital cost in addition to reducing energy requirement as it requires less packing to strip CO2 than PZAS and requires only one cross exchanger with 8 heat transfer units.