Natural Gas-fired Power Plants Research Articles

Preliminary Performance and Cost Evaluation of Four Alternative Technologies for Post-Combustion CO2 Capture in Natural Gas-Fired Power Plants

The objective of this study is to assess the technical and economic potential of four alternative processes suitable for post-combustion CO2 capture from natural gas-fired power plants. These include: CO2 permeable membranes; molten carbonate fuel cells (MCFCs); pressurized CO2 absorption integrated with a multi-shaft gas turbine and heat recovery steam cycle; and supersonic flow-driven CO2 anti-sublimation and inertial separation. A common technical and economic framework is defined, and the performance and costs of the systems are evaluated based on process simulations and preliminary sizing. A state-of-the-art natural gas combined cycle (NGCC) without CO2 capture is taken as the reference case, whereas the same NGCC designed with CO2 capture (using chemical absorption with aqueous monoethanolamine solvent) is used as a base case. In an additional benchmarking case, the same NGCC is equipped with aqueous piperazine (PZ) CO2 absorption, to assess the techno-economic perspective of an advanced amine solvent. The comparison highlights that a combined cycle integrated with MCFCs looks the most attractive technology, both in terms of energy penalty and economics, i.e., CO2 avoided cost of 49 $/tCO2 avoided, and the specific primary energy consumption per unit of CO2 avoided (SPECCA) equal to 0.31 MJLHV/kgCO2 avoided. The second-best capture technology is PZ scrubbing (SPECCA = 2.73 MJLHV/kgCO2 avoided and cost of CO2 avoided = 68 $/tCO2 avoided), followed by the monoethanolamine (MEA) base case (SPECCA = 3.34 MJLHV/kgCO2 avoided and cost of CO2 avoided = 75 $/tCO2 avoided), and the supersonic flow driven CO2 anti-sublimation and inertial separation system and CO2 permeable membranes. The analysis shows that the integrated MCFC–NGCC systems allow the capture of CO2 with considerable reductions in energy penalty and costs.

Cardiovascular System Response to Chronic Exposure to Emissions from Gas Turbines Power Plants

Objectives: Heart Rate and Blood Pressure have been reported to be susceptible to the effects of air pollution. Effect of emissions from gas turbine power station among workers is relatively unexplored. Therefore, this study aimed at assessing the effect of emissions from gas turbines on cardiovascular functions and C-reactive protein level in workers of power generating stations. Methodology: 440 individuals made up of 228 workers of gas-fired power plant stations and 212 non-power generating station workers volunteered for this study. A detailed questionnaire was carefully filled by volunteers and anthropometric data measured and recorded. Blood pressure, heart rate and C-reactive protein level (CRP) were measured using standard laboratory techniques in all subjects. Results were presented as Mean ± Standard Error of Mean (SEM) and appropriate analysis was done using Independent student’s t-test and Analysis of Variance (ANOVA). P-value Results: Result showed increased systolic blood pressure (SBP), 142.45 ± 8.87 mmHg of test subjects compared to that of the control (P 0.05) which was 121.32 ± 2.25 mmHg. However, there was no statistically significant difference in the Diastolic Blood Pressure (DBP) of the test and control groups. The Pulse Rate (PR) increased significantly in the test group (89.00 ± 0.02 bpm) when compared to that of the control group (74.34 ± 1.23 bpm). There was also an elevated plasma level of CRP, 6.69 ± 0.03 mg/L in the test group compared to the control (P Conclusion: Exposure to gas emission from natural gas-fired power plants on workers of power generating stations increased SBP, PR and C-reactive Protein level.

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Improving the performance of vacuum swing adsorption based CO2 capture under reduced recovery requirements

This work discusses the effects of reduced CO2 recovery targets, i.e., <90%, on post-combustion CO2 capture through vacuum swing adsorption. Detailed computational modeling combined with multi-objective optimization is used to study the impact of CO2 recovery on parasitic energy consumption and process productivity. The study is performed for three different CO2 compositions that are representative of flue gas from cement industries, coal-fired and natural gas fired power plants. The influence of the separation agent, the adsorbent, is explored by considering four different materials, namely Zeolite 13X, a metal organic framework UTSA-16, coconut-shell activated carbon and a hypothetical minimum-energy adsorbent. Significant reduction in energy and increase in productivities were noticed when the recovery constraints are relaxed. For instance, in the case of UTSA-16 ≈ a three times increase in productivity can be achieved without increase in parasitic energy if the CO2 recovery can be lowered from 90% to 70%. At low recoveries it is also possible to work at moderate vacuum pressures (0.1 atm), thereby making vacuum swing adsorption processes practically realizable at large-scales.

Assessing the potential of molten carbonate fuel cell-based schemes for carbon capture in natural gas-fired combined cycle power plants

This work explores two configurations of natural gas-fired combined cycles (NGCC) with molten carbonate fuel cells (MCFC) for CO2 capture. Special attention is devoted to the selection of MCFC operating conditions (trade-off between CO2 capture and voltage losses), heat integration scheme, fuel use and CO2 purification. Two schemes are considered: (i) in the first “integrated” scheme, MCFC modules are installed between the gas turbine and the heat recovery steam generator (HRSG) to maximize the efficiency of the integrated power plant; (ii) in the second “non-integrated” layout, the MCFC is located downstream of the HRSG and a regenerative heat exchanger is designed to preheat cathode reactants up to the MCFC working temperature. This study includes a full techno-economic analysis of the two layouts based on a preliminary sizing of the key-components, and a sensitivity analysis on the CO2 utilization factor. Compared to a benchmark amine scrubbing process, the “integrated” configuration shows considerably better performance (Specific Primary Energy Consumption for CO2 Avoided - SPECCA = 0.31 MJ kgCO2-1; Cost of CO2 avoided - CCA = 50 $ tCO2−1), whereas the “non-integrated” solution shows higher energy penalties but similar CO2 avoidance cost (SPECCA = 2.4 MJ kgCO2−1; CCA = 76 $ tCO2−1).

Thermodynamic and economic evaluation of an innovative electricity storage system based on thermal energy storage

One of the main issues concerning the inclusion of renewable energies as a way to produce electricity is the fluctuation of the production. This explains why there is a need for efficient solutions which will allow to store the energy when there is no need for it and release it when renewable energies are not able to sustain the production. This work concerns a Power-to-Power solution based on thermal energy storage at high temperature (around 900 °C). It relies on a simple heating loop to convert electrical energy into heat, and a thermodynamic cycle such as a gas cycle or a combined cycle to convert heat into electricity. One of the questions raised by this system is how it can be profitable from the economic point of view. Indeed a lot of studies have been conducted on energy storage, but very few propose solutions which can be relevant in terms of global costs and payback time. The aim of this study is to investigate if this system could be competitive in the European, and more specifically, French energy market. To look further into this topic, the system architecture and its components are defined. A thermodynamic model is also built to represent the behavior of the cycle. Finally, an economic discussion is performed using cost functions from the literature. The results show that the system does not accumulate enough running hours to justify high investment costs and should rely on simple technologies to insure its profitability. Furthermore, while the high capital expenditures of the whole system could be challenging, the thermal storage itself is not a big expense when compared to the cost of a natural gas fired power plant.

Energy Efficiency Monitoring in Textile Industries to Achieve GHG Emissions Reduction Target in Indonesia

Modelling is used to provide an outlook and evaluate scenarios related to energy efficiency potentials from end-user in various sectors including industrial sectors. The modelling tools used ExSS (Extended Snap Shot) and GAMS (General Algebraic Modelling System) as solver. Three scenarios were developed to envision Indonesia paths in energy savings potentials, namely business as usual (BaU or baseline) and two counter measure scenarios (CM 1 and CM2). Base year was set to year 2010, in line with NDC scenarios and projection. In the baseline scenario, it is assumed that in the future years (after 2010) there were no increase in renewable energy utilisation and rise in electricity demands would be provided by coal and natural gas fired power plants. The economic structures that were incorporated in the model for the target year 2030, was assumed to be have the same value as that of 2010’s. Accordingly, structures of energy demand in end-user sectors would not change from 2010. There would be no changes in share of transportation modes. Similarly of efficiency of equipment in household, commercial and industrial sector were also indifferent to that of the 2010 values. CM1 was developed to envision the development path to achieve energy savings through the implementation of more efficient energy technology in end-user. More efficient equipment or best available technology (BAT) were expected to be implemented in various sectors, however the penetration in industry was still 5% less than other sectors (household, commercial and transportation). At this rate, BAT penetration for household, commercial and transportation sectors could reach as high as 20%. CM2 was set to be more advanced in implementing the BAT. As much as 10% increased in BAT penetration was projected to be realised in each of end use sector, i.e., household, commercial and transportation. Although, the BAT penetration in industry sector was still 5% less than others, the BAT could rise up to 25% for industry and 30% for non-industrial sectors. Parallel with this measure, biofuel demands would also increase to 10% by force of strictly implementing regulation. Baseline scenario estimates of the total final energy demand has increased by 2.5 times, from 143,747 ktoe in 2010 to 364,627 ktoe in 2030. The associated GHG emission from the related energy consumption in 2030 was estimated to be around 1,642,009 Gg CO2e, which was higher by almost 4 times the GHG emission level in 2010 (416,530 Gg CO2e).

A Dynamic Linearization and Convex Relaxation-Based Approach for a Natural Gas Optimal Operation Problem

Addressing the non-convexity in natural gas system constraints is important under the increasing installation of natural gas-fired power plants. In this letter, a dynamic linearization and convex relaxation based approach is proposed to handle the non-convexity in the nonlinear compressors’ gas consumption equations and Weymouth equations. The proposed model is tractable and can easily incorporate the flexible transmission pipeline parameters. Numerical results demonstrate the effectiveness of the proposed approach and show the effects of flexible transmission pipeline parameters.

Integration of emerging resources in IGDT-based robust scheduling of combined power and natural gas systems considering flexible ramping products

Wind energy sources have created new challenges in power system scheduling to follow the network load. Gas fired units with high ramping could better deal with inherent uncertainties of wind power compared to other power generation sources. The natural gas system constraints affect the flexibility of natural gas-fired power plants in the electrical market. In this paper, three solutions have been proposed to cover the challenges of gas system constraints and the uncertainty of wind power: 1) using information-gap decision theory (IGDT) based robust approach to address the uncertainty caused by the intrinsic nature of wind power, 2) Integration of compressed air energy storage (CAES), and demand response (DR) in day-ahead scheduling and 3) considering flexible ramping products in order to ensure reliable operations, there must be enough ramp to eliminate the variability of wind power in real-time dispatch stage. This paper proposes an IGDT-based robust security constrained unit commitment (SCUC) model for coordinated electricity and natural gas systems with the integration of wind power and emerging flexible resources while taking the flexible ramping products into account. Numerical tests demonstrate the effect of emerging flexible resources on a reduction of system operation cost and the uncertainty of predicted wind power.

Water Enables Efficient CO2 Capture from Natural Gas Flue Emissions in an Oxidation-Resistant Diamine-Appended Metal-Organic Framework.

Supported by increasingly available reserves, natural gas is achieving greater adoption as a cleaner-burning alternative to coal in the power sector. As a result, carbon capture and sequestration from natural gas-fired power plants is an attractive strategy to mitigate global anthropogenic CO2 emissions. However, the separation of CO2 from other components in the flue streams of gas-fired power plants is particularly challenging due to the low CO2 partial pressure (∼40 mbar), which necessitates that candidate separation materials bind CO2 strongly at low partial pressures (≤4 mbar) to capture ≥90% of the emitted CO2. High partial pressures of O2 (120 mbar) and water (80 mbar) in these flue streams have also presented significant barriers to the deployment of new technologies for CO2 capture from gas-fired power plants. Here, we demonstrate that functionalization of the metal-organic framework Mg2(dobpdc) (dobpdc4- = 4,4'-dioxidobiphenyl-3,3'-dicarboxylate) with the cyclic diamine 2-(aminomethyl)piperidine (2-ampd) produces an adsorbent that is capable of ≥90% CO2 capture from a humid natural gas flue emission stream, as confirmed by breakthrough measurements. This material captures CO2 by a cooperative mechanism that enables access to a large CO2 cycling capacity with a small temperature swing (2.4 mmol CO2/g with ΔT = 100 °C). Significantly, multicomponent adsorption experiments, infrared spectroscopy, magic angle spinning solid-state NMR spectroscopy, and van der Waals-corrected density functional theory studies suggest that water enhances CO2 capture in 2-ampd-Mg2(dobpdc) through hydrogen-bonding interactions with the carbamate groups of the ammonium carbamate chains formed upon CO2 adsorption, thereby increasing the thermodynamic driving force for CO2 binding. In light of the exceptional thermal and oxidative stability of 2-ampd-Mg2(dobpdc), its high CO2 adsorption capacity, and its high CO2 capture rate from a simulated natural gas flue emission stream, this material is one of the most promising adsorbents to date for this important separation.

Observations of Methane Emissions from Natural Gas-Fired Power Plants.

Current research efforts on the atmospheric impacts of natural gas (NG) have focused heavily on the production, storage/transmission, and processing sectors, with less attention paid to the distribution and end use sectors. This work discusses 23 flights at 14 natural gas-fired power plants (NGPPs) using an aircraft-based mass balance technique and methane/carbon dioxide enhancement ratios (ΔCH4/ΔCO2) measured from stack plumes to quantify the unburned fuel. By comparing the ΔCH4/ΔCO2 ratio measured in stack plumes to that measured downwind, we determined that, within uncertainty of the measurement, all observed CH4 emissions were stack-based, that is, uncombusted NG from the stack rather than fugitive sources. Measured CH4 emission rates (ER) ranged from 8 (±5) to 135 (±27) kg CH4/h (±1σ), with the fractional CH4 throughput lost (loss rate) ranging from -0.039% (±0.076%) to 0.204% (±0.054%). We attribute negative values to partial combustion of ambient CH4 in the power plant. The average calculated emission factor (EF) of 5.4 (+10/-5.4) g CH4/million British thermal units (MMBTU) is within uncertainty of the Environmental Protection Agency (EPA) EFs. However, one facility measured during startup exhibited substantially larger stack emissions with an EF of 440 (+660/-440) g CH4/MMBTU and a loss rate of 2.5% (+3.8/-2.5%).

Advancing CO2 Capture from Natural Gas Combined Cycle Power Plants with Piperazine Scrubbing

Carbon dioxide capture and storage is widely recognized as an essential technology for limiting the global temperature rise to 2 °C by the end of the century. Technology development efforts so far focus on coal-fired power plants and other industrial sources with relatively high CO2 partial pressures. However, natural gas is increasingly used in power generation because of its abundance and low greenhouse gas impacts among the fossil fuels. For deep decarbonization that is required in the future, fossil fuels with CCS continue to play a relevant role in scenarios that balance cost of energy with climate impacts. Carbon capture from natural gas sources has been an ongoing interest to CO2 Capture Project (CCP) and its members from the oil and gas industry. This paper describes the work related to solvent-based natural gas carbon capture sponsored by CCP and pilot studies performed in collaboration with University of Texas at Austin researchers. The collaboration with University of Texas at Austin (UT) is aimed at demonstrating the application of an aqueous piperazine solution-a second-generation solvent-in a pilot plant. The goal is to test CO2 separation from synthetic flue gas representative of the exhausts from natural gas-fired combined cycle power plant (i.e. ~4 mol% CO2). The low CO2 concentration in NGCC flue gas is considered to be a challenge for many capture technologies. This work tested the performance of 5m piperazine in the UT pilot plant at a range of operating conditions, including solvent loadings, gas and liquid flow rates, assessing two different absorber configurations. High CO2 capture rates above 90% were confirmed. The pilot test results were used to verify and extend the range of applicability of the thermodynamic model developed by UT. This work increases the confidence for the application of the process models to design CCS processes for low CO2 concentrations. The model’s predictions of the pilot plant tests at low concentrations are now as accurate and reliable as those for higher CO2 concentrations where much of the data have been collected until now. Further pilot tests at NCCC are being designed to supplement the model evaluation data set for NGCC flue gas as well as to address questions related to oxidation/corrosion and cooling scheme optimization for NGCC applications.

Influence of various carbon capture technologies on the performance of natural gas-fired combined cycle power plants

Carbon capture and storage (CCS) technology has been studied actively in recent years to address global warming. This paper aimed to make a consistent comparison of different capture technologies applied to the natural gas-fired combined cycle (NGCC). Multiple power plant systems based on a standard NGCC using three different carbon capture technologies (post-combustion, pre-combustion, and oxycombustion) were proposed, and their net performance was compared. The optimal pressure ratio of the oxy-combustion technology system was obtained. The variations in the net cycle performance of the three systems were compared using the specific CO2 capture. The net power of the post-combustion capture scheme is lower than that of all other systems, but it has the highest efficiency. However, its biggest disadvantage is a much lower CO2 capture rate than the oxy-combustion capture which exhibits nearly 100 % capture rate. The conclusion is that the oxy-combustion capture would provide both the highest net efficiency and power output if a high capture rate of over 92 % was required.

Eyes on the Price: Which Power Generation Technologies Set the Market Price? Price Setting in European Electricity Markets: An Application to the Proposed Dutch Carbon Price Floor

Upon discussion of price setting on electricity wholesale markets, many refer to the so-called merit order model. Conventional wisdom holds that during most hours of the year, coal- or natural gas-fired power plants set the price on European markets. In this context, this paper analyses price setting on European power markets. We use a fundamental electricity market model of interconnected bidding zones to determine hourly price-setting technologies for the year 2020. We find a price-setting pattern that is more complex and nuanced than the conventional wisdom suggests: across all researched countries, coal- and natural gas-fired power plants set the price for only 40 per cent of all hours. Other power generation technologies such as wind, biomass, hydro and nuclear power plants as well as lignite-fired plants set the price during the rest of the year. On some markets, the price setting is characterised by a high level of interconnectivity and thus foreign influence – as illustrated by the example of the Netherlands. During some 75 per cent of hours, foreign power plants set the price on the Dutch market, whilst price setting in other more isolated markets is barely affected by foreign markets. Hence, applying the price setting analysis to the proposed Dutch carbon price floor, we show that different carbon prices have little effect on the technological structure of the price-setting units. In this respect, the impacts of the unilateral initiative are limited. There are, however, considerable changes to be observed in wholesale power prices, import/export balances as well as production volumes and subsequent CO2 outputs of lignite-, coal- and gas-fired power plants.

A General Model for Estimating Emissions from Integrated Power Generation and Energy Storage. Case Study: Integration of Solar Photovoltaic Power and Wind Power with Batteries

The penetration of renewable power generation is increasing at an unprecedented pace. While the operating greenhouse gas (GHG) emissions of photovoltaic (PV) and wind power are negligible, their upstream emissions are not. The great challenge with the deployment of renewable power generators is their intermittent and variable nature. Current electric power systems balance these fluctuations primarily using natural gas fired power plants. Alternatively, these dynamics could be handled by the integration of energy storage technologies to store energy during renewable energy availability and discharge when needed. In this paper, we present a model for estimating emissions from integrated power generation and energy storage. The model applies to emissions of all pollutants, including greenhouse gases (GHGs), and to all storage technologies, including pumped hydroelectric and electrochemical storage. As a case study, the model is used to estimate the GHG emissions of electricity from systems that couple photovoltaic and wind generation with lithium-ion batteries (LBs) and vanadium redox flow batteries (VFBs). To facilitate the case study, we conducted a life cycle assessment (LCA) of photovoltaic (PV) power, as well as a synthesis of existing wind power LCAs. The PV LCA is also used to estimate the emissions impact of a common PV practice that has not been comprehensively analyzed by LCA—solar tracking. The case study of renewables and battery storage indicates that PV and wind power remain much less carbon intensive than fossil-based generation, even when coupled with large amounts of LBs or VFBs. Even the most carbon intensive renewable power analyzed still emits only ~25% of the GHGs of the least carbon intensive mainstream fossil power. Lastly, we find that the pathway to minimize the GHG emissions of power from a coupled system depends upon the generator. Given low-emission generation (&lt;50 gCO2e/kWh), the minimizing pathway is the storage technology with lowest production emissions (VFBs over LBs for our case study). Given high-emission generation (&gt;200 gCO2e/kWh), the minimizing pathway is the storage technology with highest round-trip efficiency (LBs over VFBs).

Modeling mafic carbonation efficiency using mafic rock chemistries from Nevada, USA

Mineral carbonation is one of the many ways that are being actively investigated to sequester point-source carbon dioxide emissions. However, relations between reaction conditions, variations in reactant mineral composition, and carbon sequestration potential are poorly understood. In this study we used reaction path geochemical modeling to evaluate carbon sequestration potential during ex-situ mineral carbonation of ten mafic rock samples from Nevada, USA. Models were run using arbitrary dissolution kinetics at temperatures between 0 and 200 °C. A subset of models were run using true dissolution kinetics. In the models, carbon is sequestered in 5 mineral phases: magnesite, siderite, dolomite, calcite, and dawsonite, with magnesite and dolomite the most abundant. Dawsonite sequesters carbon at T > 150 °C in most of the arbitrary kinetics models but is not a significant carbon sink in the models using true dissolution kinetics. The arbitrary kinetics models resulted in 4.5–13 mol of carbon sequestered per kg of reacted mafic rock. True kinetics models only resulted in 1–2 mol of carbon sequestered, but the models only reacted 12.5 to 15 wt percent of the mafic rock inputs. Product minerals using the arbitrary kinetics model have volumes 150%–470% larger than the reactant volumes, whereas using true kinetics the models have a modest increase. Modeling presented herein confirms several areas of Nevada as having potential for mafic rock carbonation, some of which are located near existing coal- and natural gas-fired power plants. As shown in this study, reaction path modeling is a vital and inexpensive tool to help optimize costs and reaction conditions for ex-situ mafic rock carbonation projects.

Impacts of physical parameterization on prediction of ethane concentrations for oil and gas emissions in WRF-Chem

Abstract. Recent increases in natural gas (NG) production through hydraulic fracturing have called the climate benefit of switching from coal-fired to natural gas-fired power plants into question. Higher than expected levels of methane, non-methane hydrocarbons (NMHC), and NOx have been observed in areas close to oil and NG operation facilities. Large uncertainties in the oil and NG operation emission inventories reduce the confidence level in the impact assessment of such activities on regional air quality and climate, as well as in the development of effective mitigation policies. In this work, we used ethane as the indicator of oil and NG emissions and explored the sensitivity of ethane to different physical parameterizations and simulation setups in the Weather Research and Forecasting with Chemistry (WRF-Chem) model using the US EPA National Emission Inventory (NEI-2011). We evaluated the impact of the following configurations and parameterizations on predicted ethane concentrations: planetary boundary layer (PBL) parameterizations, daily re-initialization of meteorological variables, meteorological initial and boundary conditions, and horizontal resolution. We assessed the uncertainties around oil and NG emissions using measurements from the FRAPPÉ and DISCOVER-AQ campaigns over the northern Front Range metropolitan area (NFRMA) in summer 2014. The sensitivity analysis shows up to 57.3 % variability in the normalized mean bias of the near-surface modeled ethane across the simulations, which highlights the important role of model configurations on the model performance and ultimately the assessment of emissions. Comparison between airborne measurements and the sensitivity simulations indicates that the model–measurement bias of ethane ranged from −14.9 to −8.2 ppb (NMB ranged from −80.5 % to −44 %) in regions close to oil and NG activities. Underprediction of ethane concentration in all sensitivity runs suggests an actual underestimation of the oil and NG emissions in the NEI-2011. An increase of oil and NG emissions in the simulations partially improved the model performance in capturing ethane and lumped alkanes (HC3) concentrations but did not impact the model performance in capturing benzene, toluene, and xylene; this is due to very low emission rates of the latter species from the oil and NG sector in NEI-2011.

A study of working fluids for Organic Rankine Cycles (ORCs) operating across and below ambient temperature to utilize Liquefied Natural Gas (LNG) cold energy

Liquefied Natural Gas (LNG) contains significant amounts of cold exergy, which is normally wasted during regasification at receiving terminals. This paper addresses working fluid screening for Organic Rankine Cycles (ORCs) utilizing LNG cold energy. Due to the cryogenic temperature of LNG, the condensation temperature of an ORC should be far below ambient temperature, and the working fluid should be totally different from conventional ORCs operating above ambient temperature. However, the working fluids also depend on the cycle configuration and the natural gas target pressure. In this study, a simulation-based optimization framework is proposed to compare the performance of 22 candidate working fluids. The Particle Swarm Optimization (PSO) algorithm is adopted to optimize 5 and 7 dimensional search spaces for the combined systems operated across and below ambient temperature. Promising working fluids for ORCs considering the effect of natural gas target pressure are suggested based on the optimization results. The most energy efficient working fluids are R125, R143a, R290 and R1270 for ORCs operated below ambient temperature without waste heat utilization. For ORCs operated across ambient temperature utilizing flue gas waste heat from a natural gas fired power plant, R170, R134a and R290 perform better than other working fluids.

Bridges beyond renewable energy: Decarbonizing the global electricity sector under uncertainty

Mitigating global climate change requires decarbonizing the electricity sector, but the optimal strategy for doing so is not obvious. As power plants fueled by coal and petroleum are phased out, other generation technologies must fill the gap. While technically feasible, many low-carbon technologies are currently expensive – though costs may fall with experience. As an alternative, natural gas-fired power plants provide lower-carbon electricity – and cheaply if gas is abundant. The least-cost portfolio of generation technologies depends on several uncertain parameters. This paper presents a stylized model of the global electricity sector and evaluates several decarbonization strategies focused on three bridge technologies – natural gas, carbon capture and storage (CCS), and nuclear – over the period 2015–2050. With constraints on total demand for electricity and penetration of renewables, I find that the results are sensitive to the learning curve for CCS, the cost of natural gas, and the social cost of carbon. Depending on the true state of the world, decision-makers may find either natural gas power plants or CCS to be least-cost options for decarbonization portfolios. The expected value of information from resolving uncertainty is hundreds of billions of dollars, indicating high social benefits from investments into scientific research.

Techno-Economic Assessment of Novel vs. Standard 5m Piperazine CCS Absorption Processes for Conventional and High-efficiency NGCC Power Plants

CO2 capture and storage (CCS) can play a key role in the mitigation of greenhouse gas emissions, as it is generally applicable to many industrial sectors to limit the environmental impacts from fossil fuels usage. In this regard, natural gas-fired power plants are a suitable application for CCS technologies, although they produce flue gases with a much lower CO2 concentration (i.e. ~4 %mol) than coal-fired power plant flue gases. Amine-based solvent absorption has been widely studied as a practical solution to decarbonize post-combustion flue gases from natural gas combined cycle power plants (NGCC). This paper presents the methodology and the results of a techno-economic assessment of 5 molal (5m) piperazine (PZ) as a new potential baseline solvent for carbon capture from NGCC in three different case studies that have been considered relevant from a preliminary literature analysis. The three evaluated configurations are (i) conventional F-class NGCC coupled with the conventional absorber configuration with a direct contact cooler (DCC), (ii) conventional F-class NGCC coupled with an advanced absorber configuration (no DCC – flue gas cooling integrated within the absorber) and (iii) high efficiency, state-of-the-art H-class NGCC, coupled with the advanced absorber configuration. The present work is based on the most recent findings from University of Texas at Austin (UT) research activities, and it has been carried out by Laboratorio Energia e Ambiente Piacenza (LEAP) and Politecnico di Milano (POLIMI) researchers supported and sponsored by the CO2 Capture Project (CCP).