Post-combustion CO2 capture (PCC) plant for a typical 600 MW natural gas fueled thermal power plant was designed as a trade-off between operability and mitigation of the efficiency penalty. Two ...modified PCC plant configurations with low efficiency penalty were selected. The methodology for designing PCC plants was adapted by incorporating design constraints based on operability and the construction of absorbers. This was applied in sizing the equipment of the plants. Two configurations of absorbers were analyzed based on flue gas flow rate at full-load condition and at time-average of an assumed load variation of a power plant operating flexibly. It was found that the absorber designed at time-average load provided a reduction of approximately 4% in the purchased cost of absorbers. The performance of the designed plants under power plant load variation, flow maldistribution and variable capture ratio was analyzed using off-design condition simulations. The absorber designed at full-load condition was found to lead to lower reboiler duty in order to maintain a similar capture rate to that of the other absorber during part-load operation. Dynamic simulations of the plants with the existing control structure were performed under similar power plant load variations to confirm their operability, and suggestions for selecting one of them were presented.
•Presented method of selection and design of PCC process for NG based power plant.•Identified operational limits of MEA based PCC plants at part-load of power plant.•Identified 7%-point average efficiency penalty for periodic operation of PCC plant.
•Lifetime assessment of different concepts for energy supply to offshore facilities.•Concepts based on local power generation and plant electrification were considered.•The optimization of the ...operating strategy can reduce carbon dioxide emissions.•Electrification and offshore combined cycles had the best environmental performance.•The benefit of electrification is strongly influenced by the emission factor.
This paper assesses different concepts for efficient supply of power and heat to specific offshore installations in the North Sea, with the objective of cutting carbon dioxide emissions. The concepts analyzed include solutions with on-site power generation, full plant electrification, and hybrid solutions where power can be either generated locally or taken from the onshore grid. A detailed modeling of the power generation system was carried out, enabling design and off-design simulations. Plant power and heat demand profiles were used to evaluate the various concepts throughout the entire field’s life. A first analysis of the common on-site power generation systems revealed the possibility of cutting carbon dioxide emissions simply by optimizing the operating strategy. Overall, the assessment of the different concepts showed that full plant electrification and the implementation of an offshore combined cycle have the potential to substantially reduce cumulative carbon dioxide emissions. A sensitivity analysis of the carbon dioxide emission factor, associated with the grid power, stressed how this parameter has a strong influence on the analysis outputs and, thus, needs to be thoroughly assessed. Similarly, the impact of increased plant heat demand was evaluated, showing that advantages connected to the plant electrification tend to diminish with the increase in heat requirements.
Effective heat and power supply to offshore installations leads to environmental benefits, but the efficiency is often limited by requirements and constraints connected to the offshore environment. ...An exergetic analysis of gas turbines exhaust heat recovery on offshore platforms is performed to identify optimal approaches to produce heat and power. Two different configurations are presented, with heat delivery at two temperature levels and power production by an organic Rankine cycle (ORC). In one system (cascade), the high temperature heat is taken from the exhaust after the ORC, while low temperature heat is taken from the ORC condenser. Alternatively, high and low temperature heat is taken from the exhaust gas before the ORC feeds on the remaining exhaust thermal energy (series system). Four different working fluids (three siloxanes, one refrigerant) are considered. In addition, the exergetic effects of the heat loads and heat source temperatures are investigated. The results revealed that MM and R124 are the best working fluids for the cascade and series system, respectively. A recuperated ORC in the series system improve the siloxane results, with MM as the best working fluid. Moreover, decreasing the ORC minimum pressure in the series system makes considerable improvement.
•Gas turbine exhaust heat recovery by ORC was studied to supply energy offshore.•Two configurations (cascade and series) and four working fluids were proposed.•The performance at generic offshore platforms was evaluated.•MM and R124 are the best working fluids for the cascade and series system.•Siloxanes benefit from a recuperated cycle and subatmospheric condensing pressures.
This paper discusses the limitations and prospects of using equilibrium-based column models for the dynamic simulation of post-combustion CO2 capture processes. Based on their features, one of three ...available commercial process simulators was chosen for this study. A pilot plant configuration adopted from literature was modeled and simulated using this simulator. Simulation results were compared with plant data and with results using standard rate-based models as available in literature. Temperature profiles in columns and overall mass and energy balances were found to be similar to plant data; however, CO2 capture-rate, reboiler-duty, and rich-loading using the model were overestimated. A method of reduced stage efficiencies in the absorber was used, which improved performance prediction further with a maximum deviation of 5%. Further, this dynamic model was used to analyze the process subjected to variation in flue gas flow-rate with a similar trend of futuristic power plants by controlling either liquid to gas ratio or CO2 capture-rate. Controlling liquid to gas ratio provided more control over the reboiler-duty while controlling the capture-rate focused on maintaining a certain capture ratio. The advantages and disadvantages of both methods are discussed and based on that, the controlling capture ratio was found suitable for using while power plant works flexibly with stringent emission regulations.
Power cycles on offshore oil and gas installations are expected to operate more at varied load conditions, especially when rapid growth in renewable energies puts them in a load-following operation. ...Part-load efficiency enhancement is advantageous since heat to power cycles suffer poor efficiency at part loads. The overall purpose of this article is to improve part-load efficiency in offshore combined cycles. Here, the organic Rankine bottoming cycle with a control strategy based on variable geometry turbine technology is studied to boost part-load efficiency. The Variable Area Nozzle turbine is selected to control cycle mass flow rate and pressure ratio independently. The design and performance of the proposed working strategy are assessed by an in-house developed tool. With the suggested solution, the part-load organic Rankine cycle efficiency is kept close to design value outperforming the other control strategies with sliding pressure, partial admission turbine, and throttling valve control operation. The combined cycle efficiency showed a clear improvement compared to the other strategies, resulting in 2.5 kilotons of annual carbon dioxide emission reduction per gas turbine unit. Compactness, autonomous operation, and acceptable technology readiness level for variable area nozzle turbines facilitate their application in offshore oil and gas installations.
•Short-term loads variation process of plants is modeled with field regulation logic.•Feasibility of dispatched demands is ensured in the improved CHPED model.•The improved CHPED model enhances ...operational economy and reliability of plants.•The improved CHPED model can be applied in the real-time field operation of plants.•Influence rules and reasons of heat load ramp rates on CHPED results are studied.
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.
•The proposed method can limit equipment damage in different scenarios.•Damage can be reduced 40% with a revenue loss of less than 1%.•Different damage mechanisms in the equipment can be included in ...the method.•Variable uncertainty in power demand and price can be included.•Adequate selection of material design temperature reduces deterioration.
Renewable energy sources have been the focal point to decarbonise the power sector. The large deployment of these intermittent power generation units requires mechanisms to balance the grid. Thermal power plants can provide this service by increasing the number of start-ups, shut-downs, and intraday ramps at the expense of higher deterioration in critical equipment, including high-pressure steam drums, turbine rotors and blades, and high-temperature heat exchangers and pipes. This work proposes a method to formulate the power generation scheduling of thermal power plants as a stochastic optimisation problem with limitations on the maximum damage in critical components. This method models the uncertainty associated with intermittent power generation from renewable sources with a scenario-tree whilst computing the deterioration of the equipment in each scenario to limit the maximum damage. Scheduling of a flexible natural gas combined cycle demonstrated how this methodology can reduce the deterioration of the superheating heat exchanger of the power plant with minimum detriment in power generation and revenue. Furthermore, the effect of the design temperature of the material on the total damage was analysed for a broad range of temperatures and operating profiles, showing how adequate selection of design temperature can reduce the deterioration of the equipment and enhance its lifetime.
The utilization of combined cycles for offshore cogeneration of power and heat is an attractive option to reduce the CO2 emissions directly related to the oil and gas sector. Main challenges for ...their efficient implementation are the potentially large heat-to-power ratios and the variability of power and heat requirements throughout the different stages of a field’s lifetime. This paper aimed to provide the first elements for an assessment of the technology. Two combined cycle configurations were evaluated (backpressure and extraction steam turbine cycle), as well as different scenarios of power and heat requirements. The optimum design approach was firstly investigated. Designing the combined cycle at the end-life conditions, rather than at peak conditions, demonstrated to return better overall performance, when the entire plant’s lifetime is considered. A comparative analysis between the defined optimum designs was then carried out. Although the backpressure steam turbine cycle demonstrated to be feasible in all the cases analyzed, it showed to be effective only for offshore installations characterized by low temperature large process heat demands. On the other hand, the extraction steam turbine cycle could not meet large process heat demands but it was very attractive when the heat requirements were more limited, irrespective of the temperature at which this heat was requested.
•Maximum gas turbine’s load gradient is the main limitation during load changes.•Gas turbine under-shooting compensates the steam cycle’s slow transient.•Proposed control methodology is able to ...predict stresses in thick-walled components.•Stress monitoring allows optimal and safe control sequences under tight constraints.•Suitability of the proposed methodology for start-up and shut-down applications.
Flexible natural gas combined cycles will play a fundamental role in future electric markets. Stresses in thick-walled components and gas turbine load ramps are arguably the main limiting factors during transient operation. Classical control strategies as PID are not suitable to incorporate technical constraints such as stress limits. This work presents a control methodology based on model predictive control where the stress in the walls of the high pressure drum and the first high pressure steam turbine rotor are computed simultaneously with the optimal control sequence. Thus, the maximum allowable stress in this equipment can be set as a constraint and the control actions imposed in the power plant ensure that these limits are not exceeded. Two cases simulating flexible operation under realistic conditions and tight constraints on the stress limits are included. Results show that with the proposed control methodology the natural gas combined cycle can respond to load step changes of 165 MW in 300 s, and can operate close to the material maximum stress limit without exceeding it. The robustness and flexibility of this methodology allows its application to different operation conditions such as start-ups and shut-downs.
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