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• Enhanced single-loop control approaches compared to proportional-integral scheme. • Efficient control demonstrated for several flexible power plant operation scenarios. • Adaptive tuning showed similar control performance with less aggressive input usage. • Combined feedback and feedforward structure improved control of sorbent temperature. • Measurement delays have a significant effect on the relative controller performance. Using a model in gPROMS, we study a Zeolite 13X-based moving bed temperature swing adsorption (MBTSA) process designed to capture CO 2 from a coal-fired power plant. Two enhanced single-loop control strategies were compared to a proportional-integral configuration for variations in power plant load, control variable setpoints, flue gas CO 2 concentration and external heat source temperature. Measurement delays were also investigated. Adaptive adjustment of controller parameters with system load gave smoother and narrower manipulated variable profiles and efficient CO 2 recovery setpoint tracking. The controller gain is the most important parameter for adaptive tuning. A combined feedback and feedforward scheme showed improved control of the regenerated sorbent temperature, possibly due to better decoupling of the higher-level control loops. When delays were considered, the investigated strategies significantly outperformed the reference case for CO 2 recovery control. The results demonstrate that the MBTSA process can be efficiently controlled for several disturbances and changes in operation. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

This paper discusses the limitations and prospects of using equilibrium-based column models for the dynamic simulation of post-combustion CO 2 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, CO 2 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 CO 2 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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Post-combustion CO 2 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. [ABSTRACT FROM AUTHOR]

Global concerns regarding greenhouse gas emissions and global warming have necessitated the speed up in using renewable energies and more efficient use of fossil fuels in the oil and gas industry. Harvesting gas turbine heat by organic Rankine bottoming cycles has raised as a potential solution to cut carbon dioxide emissions in offshore oil and gas installations. Offshore power cycles are expected to operate most of their operational life at part-loads where they suffer from poor efficiency. The purpose of this article is to boost the part-load efficiency of offshore organic Rankine cycles and keep it as close as possible to the design value. Here an operational strategy based on cooling water flow control is developed and added to a sliding pressure control logic and a variable area nozzle turbine control strategy. An in-house tool is developed for the design of organic Rankine cycles and the simulation of off-design control strategies. A design methodology is presented to optimize the cycle power output while minimizing the cycle footprint offshore. The proposed control strategy was successful in keeping the part-load efficiency close to design value and achieving a 5% reduction of annual carbon dioxide emissions. [ABSTRACT FROM AUTHOR]

Offshore oil and gas installations are mostly powered by simple cycle gas turbines. To increase the efficiency, a steam bottoming cycle could be added to the gas turbine. One of the keys to the implementation of combined cycles on offshore oil and gas installations is for the steam cycle to have a low weight-to-power ratio. In this work, a detailed combined cycle model and numerical optimization tools were used to develop designs with minimum weight-to-power ratio. Within the work, single-objective optimization was first used to determine the solution with minimum weight-to-power ratio, then multi-objective optimization was applied to identify the Pareto frontier of solutions with maximum power and minimum weight. The optimized solution had process variables leading to a lower weight of the heat recovery steam generator while allowing for a larger steam turbine and condenser to achieve a higher steam cycle power output than the reference cycle. For the multi-objective optimization, the designs on the Pareto front with a weight-to-power ratio lower than in the reference cycle showed a high heat recovery steam generator gas-side pressure drop and a low condenser pressure. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Abstract: One option for pre-combustion CO2 capture in power plants is the integrated reforming combined cycle (IRCC). IRCCs have previously been studied from multiple viewpoints: thermo-economic analysis, process optimization, environmental impact, and plant flexibility. This paper is focused on the design of the heat recovery steam cycle (HRSC), including the heat recovery steam generator (HRSG), and aims to define the optimal steam cycle configurations for plant efficiency and dual-fuel flexibility. A recently developed optimization algorithm was successfully applied to obtain a set of flexible and efficient designs for IRCCs. Results showed that the preferred designs consisted of a dual-pressure level HRSG with reheat and limited supplementary firing in duct burners, high-pressure evaporators and economizers in the syngas coolers, limited high-pressure level (140–154bar), and feedwater preheating. The most attractive optimized dual-pressure designs showed improvements of approximately 0.5% points in the net plant efficiency compared to the non-optimized base case. The resulting net plant efficiency was about 45.8% with a net power output of around 425MW for the best cases. [Copyright &y& Elsevier]

Abstract: A systematic approach to quantify uncertainties in an integrated reforming combined cycle (IRCC) process model employing CO2 capture is presented. IRCC involves reforming of natural gas into a hydrogen-rich fuel which is then used as gas turbine fuel. Included in an IRCC plant is also a steam bottoming cycle. The analysis treats uncertain parameters as random variables whose probability distributions are estimated from limited existing information using entropy maximization. Uncertainties of model parameters were propagated through the process model using the deterministic equivalent modeling method as a computationally efficient alternative to Monte Carlo simulations. The method also quantifies the effect of each parameter on the total uncertainty of model outputs. The IRCC process model was evaluated in terms of four performance metrics: (1) net plant power output, (2) net plant efficiency, (3) CO2 capture rate, and (4) CO2 emitted per kWh of generated electricity. Simulation results showed that there was considerable uncertainty in the predicted net power output whereas the other three variables were less affected by input uncertainties. The IRCC plant was predicted to have a median net plant efficiency of 43.4% with a standard deviation of 0.5%, representing a loss of approximately 13%-points compared to a natural gas combined cycle plant without CO2 capture. Results also indicated that the probability of meeting the requirement of at least 85% CO2 capture rate for the plant was approximately 95%. Parameters with the largest impact on uncertainties of power output and efficiency predictions proved to be gas turbine inlet temperature, and compressor and turbine efficiencies. For the CO2 emissions, the equipment pressure drop and the steam-to-carbon ratio proved important. Therefore, the focus of future work should be to reduce uncertainties in these parameters in order to improve the confidence of the IRCC model. [Copyright &y& Elsevier]

In this work, we use a plantwide control framework to systematically identify the control objectives, operational and environmental constraints, and degrees of freedom for a heat to power cycle with a drum, one pressure level and with power as the only valuable product. After controlling the active constraints and the unstable inventories, we are left with the fuel (MV1) as the only degree of freedom with a significant steady-state effect. However, the steam valve (MV2) can be used as a dynamic degree of freedom, to improve the response in transient operation while its steady-state effect is negligible. The result is an unified and systematic perspective on the optimal control operation problems for heat-to-power cycles. [ABSTRACT FROM AUTHOR]

• Maximum gas turbine load gradient is the main limitation during load changes • Linear MPC shows superior performance than nonlinear MPC • Possible to resort to nonlinear MPC when linear stress modelling is not feasible • Proposed control methodology is able to predict stresses in thick-walled components • Stress monitoring allows optimal and safe control sequences under tight constraints In future energy markets, traditional thermal power plants are expected to cycle more to adapt their operation to the intermittent power generation of renewable energy sources. Gas turbine load ramps and stresses in thick-walled equipment of the steam cycle are arguably the main limitations in the flexible operation of natural gas combined cycles. This work proposes a control strategy based on model predictive control with stress monitoring to overcome both limitations and enhance the flexible operation of thermal power plants. The linear and nonlinear formulation of the problem included in the model predictive control strategy are described, and two different modelling approaches for the stresses in the high pressure drum and steam turbine rotor are presented. The results demonstrate that the proposed control strategy is capable of computing optimal control sequences without exceeding the maximum allowable stress in critical components and the ramp rates of the gas turbine. The comparison between the linear and nonlinear formulations shows the superior performance of linear model predictive control and suggests that the nonlinear formulation should only be used when the stress models can not be expressed as a linear system of equations. [ABSTRACT FROM AUTHOR]

This paper presents a set of steady-state and transient data for dynamic process model validation of the chemical absorption process with monoethanolamine (MEA) for post-combustion CO2 capture of exhaust gas from a natural gas-fired power plant. The data selection includes a wide range of steady-state operating conditions and transient tests. A dynamic process model developed in the open physical modeling language Modelica is validated. The model is utilized to evaluate the open-loop transient performance at different loads of the plant, showing that pilot plant main process variables respond more slowly at lower operating loads of the plant, to step changes in main process inputs and disturbances. The performance of four decentralized control structures is evaluated, for fast load change transient events. Manipulation of reboiler duty to control CO2 capture ratio at the absorber's inlet and rich solvent flow rate to control the stripper bottom solvent temperature showed the best performance. [ABSTRACT FROM AUTHOR]

Currently, most of the adjoint-based design systems documented in the open literature assume that the fluid behaves as an ideal gas, are restricted to the optimization of a single row of blades, or are not suited to impose geometric constraints. In response to these limitations, this paper presents a gradient-based shape optimization framework for the aerodynamic design of turbomachinery blades operating under nonideal thermodynamic conditions. The proposed design system supports the optimization of multiple blade rows, and it integrates a computer-aided design (CAD)-based parametrization with a Reynolds-averaged Navier-Stokes (RANS) flow solver and its discrete adjoint counterpart. The capabilities of the method were demonstrated by performing the design optimization of a single-stage axial turbine that employs isobutane (R600a) as working fluid. Notably, the aerodynamic optimization respected the minimum thickness constraint at the trailing edge of the stator and rotor blades and reduced the entropy generation within the turbine by 36%, relative to the baseline, which corresponds to a total-to-total isentropic efficiency increase of about 4 percentage points. The analysis of the flow field revealed that the performance improvement was achieved due to the reduction of the wake intensity downstream of the blades and the elimination of a shock-induced separation bubble at the suction side of the stator cascade. [ABSTRACT FROM AUTHOR]

Abstract: Improved energy efficiency is an issue of increasing importance in offshore oil and gas installations. The power on offshore installations is generated by gas turbines operating in a simple cycle. There is an obvious possibility for heat recovery for further power generation from the exhaust heat. However, the limited space and weight available makes the inclusion of bottoming cycles challenging. Due to its high working pressure and thereby compact components CO2 (carbon dioxide) could be a viable solution, combining compactness and efficiency. An in-house simulation tool is used to evaluate the performance of CO2 bottoming cycles at design and off-design conditions. Both a simple recuperated single stage cycle and a more advanced dual stage system are modelled. Results from simulations show a potential for 10–11%-points increase in net plant efficiency at 100% gas turbine load. Also off-design simulations taking the variation in heat exchanger performance into account are performed showing that the bottoming cycle improves the off-design performance compared to the standard gas turbine solution. Even at 60% GT (gas turbine) load, the combined cycle with CO2 bottoming cycle can achieve up to 45% net plant efficiency, compared to 31% for only the gas turbine. [Copyright &y& Elsevier]

An opportunity to decarbonise the offshore oil and gas sector lies in the integration of renewable energy sources with energy storage in a hybrid energy system (HES). Such concept enables maximising the exploitation of carbon-free renewable power, while minimising the emissions associated with conventional power generation systems such as gas turbines. Offshore plants, in addition to electrical and mechanical power, also require process heat for their operation. Solutions that provide low-emission heat in parallel to power are necessary to reach a very high degree of decarbonisation. This paper investigates different options to supply process heat in offshore HES, while the electric power is mostly covered by a wind turbine. All HES configurations include energy storage in the form of hydrogen tied to proton exchange membrane (PEM) electrolysers and fuel cells stacks. As a basis for comparison, a standard configuration relying solely on a gas turbine and a waste heat recovery unit is considered. A HES combined with a waste heat recovery unit to supply heat proved efficient when low renewable power capacity is integrated but unable to deliver a total CO2 emission reduction higher than around 40%. Alternative configurations, such as the utilization of gas-fired or electric heaters, become more competitive at large installed renewable capacity, approaching CO2 emission reductions of up to 80%. [ABSTRACT FROM AUTHOR]

Flexible thermal power plants integrated with CO 2 capture systems can balance the intermittent power generation of renewable energy sources with low-carbon electricity. Among these power systems, natural gas combined cycles will play a fundamental role because of their faster operation and higher efficiency. Optimisation-based control strategies can enhance the flexible power dispatch of these systems and improve their performance during transient operation. This work proposes a model predictive control (MPC) strategy to stabilise these power plants with post-combustion CO 2 capture based on temperature swing chemical absorption and provide offset-free reference tracking. A delta-input formulation with disturbance modelling is proposed, as it provides more efficient computation with offset-free control. Data-based models were developed to replicate the performance of the actual power and capture plants. Prediction of nonlinear behaviour was accomplished by creating a network of local linear models, which allowed the formulation of the dynamic optimisation program in the MPC strategy as a convex quadratic programming problem. A case study demonstrated the effectiveness of the proposed MPC to balance drastic changes on power demand and keep specified capture ratios. Furthermore, the reduced deviations achieved in the reboiler temperature suggest that the nominal value of this parameter could be increased to improve the desorption process without risks of reaching temperatures where the solvent would degradate. [ABSTRACT FROM AUTHOR]

Increasing the share of renewables in energy markets influences the daily operation of thermal power units. High capacity power units are more frequently operated to balance power grids and, thus, steam boilers are exposed to unfavorable transient states. The aim of this work was to perform thermal and structural analyses of a boiler's outlet steam header, with a capacity of 650∙103 kg/h (180 kg/s) of live steam. Based on the measured steam pressure and temperatures on the outer surface of the component, transient temperature fields were determined by means of an algorithm that allows determination of transient stress distributions on the internal and external surfaces, as well as at stress concentration regions. In parallel, a finite element method simulation was performed. A comparison of the obtained results to a finite element analysis showed satisfactory agreement. The analyses showed that the start-up time could be reduced because the total stress did not exceed the allowed values during the regular start-up of the analyzed power unit. The algorithm was efficient and easy to implement in the real control systems of the power units. The numerical approach employed in the presented algorithm also allowed for determination of the time- and place-dependent heating rate value, which can be used as input data for the control system of the power unit. [ABSTRACT FROM AUTHOR]

Abstract 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. Highlights • 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. [ABSTRACT FROM AUTHOR]

This work considers the closed-loop behavior of a moving bed temperature swing adsorption process designed to capture CO 2 from a coal-fired power plant. Four decentralized control strategies were studied based on step changes and ramps of flue gas feed flow rate and controller setpoint changes. A proportional-integral (PI) control configuration, where CO 2 purity was controlled by hot fluid velocity to the desorption section and CO 2 recovery was controlled by the sorbent flow rate, demonstrated the overall best performance. The 99% settling time for higher-level control variables varied from 0 to 13 min for most control configurations and the settling time for CO 2 purity was generally longer than for CO 2 recovery. The simulations show that using ratio controllers lead to larger offsets but can give around 10 times faster purity response compared to PI-control. All investigated control combinations were able to keep the controlled variables relatively close to the setpoints and the largest relative steady state setpoint offset was 2%. • Process control of moving bed temperature swing adsorption CO 2 capture was studied. • A proportional-integral control configuration showed the overall best performance. • Ratio controllers give larger offsets but faster purity response than PI control. • All control combinations gave relative steady state offsets less than 2%. [ABSTRACT FROM AUTHOR]

This work investigates the interactions that occur between a supercritical pulverized-coal-fired power plant and a downstream CO2-absorption process during load changes in the power plant by linking the dynamic models of the two systems. The derived dynamic model for this integrated system is implemented in the dynamic modeling and simulation software Dymola. The operation of the integrated system is investigated in two modes of operation, considering various power plant loads and levels of steam availability for the CO2-absorption process. Several schemes for control of the CO2-absorption process, which have been suggested in the literature, are implemented for the integrated system, and their effects on power plant operation are evaluated. Comparison of the simulation results obtained through varying the power plant load with and without CO2 absorption reveal that the CO2-absorption process has slower process dynamics than the power plant cycle, with the CO2 absorption stabilizing in more than 1 h, while the power generation generally stabilizes in 6-9 min in the power plant both with and without CO2 absorption. The control scheme used for the CO2-absorption process is important, because pairing of the control variables in relatively slow control loops increases the settling time of the power plant by up to 30 min with respect to power output. The results suggest that the investigated CO2-absorption process does not affect significantly the load-following capabilities of the power plant. Redirecting steam from the CO2-absorption process to the low-pressure turbine section in order to increase power generation (during a hypothetical peak-load demand) results in fluctuations of process variables in the power plant during the 2 h of reduced steam availability to the CO2-absorption process. This is observed for both control schemes applied to the CO2-absorption process, and the power generation is not stabilized until the operation is restored to full load. [ABSTRACT FROM AUTHOR]

Combined heat and power dynamic economic dispatch (CHPDED) is one of the key technologies for the efficient operation of natural gas combined cycle (NGCC) plants in integrated energy systems. In this study, based on the actual operational characteristics of NGCC plants at combined heat and power mode, a plant advanced loads variation capacity model is developed. The advanced loads variation capacity models of NGCC plants are integrated into the CHPDED model to guarantee the feasibility of the dispatched demands. Moreover, a field operational data based simplification method for the advanced loads variation capacity model is proposed to alleviate the computational burden. The field operational data of an actual NGCC station is taken to perform case studies. The calculation cases show that all the dispatched demands calculated from the CHPDED model with advanced loads variation capacity models are feasible. Furthermore, the influence of the heat load variation process on the power load adjustment process is employed to achieve better dispatch results. Compared with CHPDED models in the existing research, the CHPDED model with advanced loads variation capacity models significantly improves the feasibility of the dispatched demands, thereby enhancing the real application value of CHPDED in the field operation of NGCC plants. • An advanced loads variation capacity model of an NGCC plant at CHP mode. • Actual operational characteristics of an NGCC plant are considered in detail. • Feasibility of dispatched demands is greatly improved in the proposed CHPDED model. • The proposed CHPDED model enhances operational reliability and economy of plants. • Field operational data of an actual NGCC station is taken to perform case studies. [ABSTRACT FROM AUTHOR]

Turbomachinery design is increasingly carried out by means of automated workflows based on high-fidelity physical models and optimization algorithms. The parametrization of the blade geometry is an essential aspect of such workflows because it defines the design space in which an optimal solution can be found. Currently, parametrization methods used for this purpose are often tailored to one particular type of turbomachinery blade, do not provide shape derivatives required for gradient-based optimization, or are not suited to re-parametrize a baseline blade geometry defined by a set of scattered point coordinates in a systematic way. This paper thus presents a general blade parametrization method for axial, radial, and mixed flow blades based on typical turbomachinery design variables and NURBS curves and surfaces. The shape derivatives are computed by means of the complex-step method, allowing the integration of the parametrization into gradient-based shape optimization workflows. In addition, the method enables the re-parametrization of a blade geometry defined by a cloud of points by solving a two-step optimization problem. The capabilities of the method are demonstrated by replicating eight blade geometries in two and three dimensions with an accuracy comparable to the tolerances of current manufacturing technologies. • Formulation of a unified geometry parametrization method for turbomachinery blades. • Sensitivity computation by means of the complex-step method. • Systematic matching method to parametrize a blade from scattered point coordinates. • Application of the method to replicate eight exemplary blade geometries. [ABSTRACT FROM AUTHOR]

Electrification of offshore oil and gas installations on the Norwegian continental shelf is one of several options to decrease the CO2 emitted from these installations. However, there is an ongoing debate regarding how the increased electricity consumption will influence the CO2 emissions in the power market, both in the short-run and in the long-run. This paper aims to address the issue and investigate the feasibility of the electrification of a large offshore area in the North Sea in comparison to standard concepts to supply energy offshore. A novel integrated model was developed for the purpose that includes and combines a process model of the offshore power generation units and a model of the European power system. The integration of the two models allows to simultaneously simulate the behavior of the offshore energy conversion systems and the effect of electrification on the onshore power system. The outcomes of the analysis show that the environmental performance of electrification is strongly affected by the selected approach to quantify the CO2 emissions associated with power from shore. Taking standard methods to supply offshore energy as basis for comparison, the marginal effect of electrification would result in increased CO2 emissions (+40%), while the average effect would entail large reductions in CO2 emissions (−48% to −90%), the extent of which depends on the geographical scope selected. An analysis on the economics of electrification indicates that its economic viability would be challenging and would not be favoured by a strong European commitment towards environmental policies since the expected increase of power price will outbalance the gains for the reduced emission costs. [ABSTRACT FROM AUTHOR]