Multi-objective optimisation of CCs using simulation, heat integration and cost estimation

Using multi-objective optimisation in the design of CO2 capture systems for retrofit to coal power stations

In chemical engineering design, process plants are often capable of turndown and flexible operation to maximise profitability depending on demand and price signals, and the optimisation of these processes needs to take into account the variability in the plant operation. By performing the optimisation with flexible operating conditions the overall plant performance can be improved. The optimisation process makes use of two computational modelling techniques: multi-objective optimisation (MOO) and surrogate modelling. Multi-objective optimisation allows for the optimisation of two or more competing variables simultaneously. In the cases studied here, the long individual simulation time coupled with the large number of individual simulations required meant that the total simulation time was prohibitive for dynamic MOO. In order to reduce computation time surrogate models of the processes are developed using artificial neural networks. A statistical dynamic modelling framework within a multi-objective optimisation methodology is developed to optimise a process plant’s performance. Here the dynamic modelling is used to optimise the economic and environmental performance of natural gas combined cycle power plant systems fitted with carbon capture and storage (CCS) and solar thermal energy (STE) in a time-integrated MOO framework. This framework allows for variable process inputs and flexible operation based on external signals, such as product price. By introducing a probabilistic approach to the modelling of flexible operation allows for more data to be included in the analysis. The methodology for dynamic modelling of flexible operation could be applied to other industrial processes that face similar dynamic economic and/or environmental conditions. From a CCS standpoint dynamic MOO was used to show that variable capture can be used to make the CCS plant more profitable over steady state operation. At a capture rate of 80 % the NPV of a gas turbine combined cycle with CCS improved by 38 m$AU by utilising flexible operation of the capture process. This also allows for various economic scenarios to incentivise the reduction of CO₂ emissions from natural gas based power plants, with the use of CCS and STE used to reduce the greenhouse emissions. The economic strategies of a carbon price and governmental grants are investigated to determine the levels of policy help to incentivise implementing CO₂ reduction technologies. In order to achieve a financial incentive for limiting CO₂ emissions from a combined cycle power plants equipped with CCS a government co-investment grant of 50 % of the capital costs and a carbon price of 83 $AU/tCO₂ is required.

Economic feasibility of CO2 capture from oxy-fuel power plants considering enhanced oil recovery revenues

Climate change is likely to be (and is) more serious and likely to proceed much more rapidly than was previously thought. This article surveys and evaluates the technology of processing carbon dioxide and hydrogen into sustainable synthetic carbohydrate fuels and the related economics in relation to a particular route, the capture of carbon dioxide from the flue gas stream of gas burning power stations, provided the gaseous fuel is of biogenic origin. Biogenic methane is renewable and can, after combustion into carbon dioxide, via carbon capture be further processed into a range of carbohydrate fuels, or alternatively captured for final storage under carbon capture and store (CCS). It is proposed that the air intake of a power station be replaced by cooled flue gases consisting mainly of carbon dioxide, enriched with oxygen obtained by electrolysis of water. The co-produced hydrogen can then be processed further into more easily transportable and storable forms of fuel. This implies that a gas-fired power station is not so much a means of producing energy, but rather of producing pure carbon dioxide. The capture process as such is the same as the one which arises if the purpose is carbon capture and use or CCS in which case capture of CO2 from the combustion of methane from biogenic origin amounts to negative emissions. The indirect route of supplying and using energy via the production of carbohydrate fuels requires much more primary energy than the direct use of electricity does. For this reason, use of that indirect route is efficient for aviation, where the direct route of electric power is impractical. For shipping, there also is the alternative of the implicit transport of hydrogen as part of ammonia. It is assumed that the use of biogenic methane followed by processing of the captured carbon dioxide into synthetic hydrocarbon fuels is in combination with volcanic carbon hydroxide, sufficient to meet the demand for hydrocarbon fuels. Capture of carbon dioxide from biogenic methane can also be applied in the context of CCS.

Rapid industrialization and urbanization in the 20th century have led to increasing volumes of carbon dioxide being released into the atmosphere[...]

Capturing rogue carbon

Heat integration techniques are now widely used for energy saving in petroleum processes. In this paper, an industrial hydrocracking process (UOP license) is retrofitted by pinch analysis as a significant tool for heat integration. The hydrocracking process is a main important conversion process in oil refineries and there has been sustained effort to improve its energy efficiency. Application of pinch analysis in retrofit of this process shows the heat exchanger network is operated efficiently. However, a large amount of energy is wasted from the hydrocracking unit, which their condition make no of use directly by the process during pinch analysis. Actually, most of the refining petroleum processes use considerably more energy than the operational minimum energy requirements because of their energy losses. These external energy losses are due to many factors, including normally inefficient or outdated equipment and process design, inadequate heat recovery, and poor integration of heat sources and sinks. However, without identifying the quality of the energy losses, it is difficult to determine how much of that energy is feasible to recover under realistic plant operating conditions. This is where exergy analysis can significantly assist in determining energy recovery opportunities. Thus, this paper is addressed to researchers who are assessing the quality of energy wasted in hydrocracking process, by using the principles of both pinch and exergy analysis. Based on the result obtained, the flue gas exhaust and the high pressure drop in reaction section can be considered as the exergy loss sources in this process. Moreover, the portion of waste energy that can be practically recovered is quantified.

Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs). The CCS process captures carbon dioxide (CO2) generated at large-scale industrial sources (power plants, refineries, gasification facilities, etc.) and transports it to an injection site to be permanently stored in the subsurface. With extensive research linking GHG concentrations in the atmosphere to observed changes in global temperature patterns, CCS technology could play an important role in policy efforts to limit the global average temperature rise. Even with the wealth of experience already in place within the oil and gas industry, the obstacles to advancing CCS to the forefront of GHG mitigation technologies remain significant. Large-scale CO2 injection projects remain primarily in the realm of commercial CO2-EOR (enhanced oil recovery) projects. The key challenges to enabling CCS include cost-effective capture and transport of industrial CO2, clear access to pore space for CO2 storage in geologic formations, proven methodologies for demonstrating storage integrity, and dissemination of best practices. SPE members can play a significant role in addressing these challenges. Cost-Effective Capture of Power Sector and Industrial CO2 A major technical challenge facing capture at electric generating facilities is that the CO2 concentration in large-volume flue streams is quite low. Current removal technologies include techniques that apply amines, chilled ammonia, membranes, and ionic liquids to strip the CO2 from the flue stream. However, these technologies were developed to handle smaller-scale operations and higher-CO2-purity streams. When applied to large electric generating plants, process efficiency is reduced, and the energy penalty associated with the capture process drives up costs, increasing the levelized cost of electricity by 50% or more, depending on local factors. Also, to accommodate the substantial volumes of the CO2 and flue gas at full-scale industrial sources, the removal technologies require significant scale up and footprint for deployment. While early movers are developing large-scale capture demonstrations such as SaskPower’s Boundary Dam Project, Southern Company’s Kemper Energy Facility (Fig. 1), and NRG’s Petro Nova Facility, we are still very early on the “learning curve.” Support for more development of next-generation capture technologies and large demonstrations is required to push us down the cost curve. This involves reducing the cost of materials and construction, parasitic costs related to energy for operations, compression, and operation and maintenance costs.

This work addresses the indirect heat integration (i.e. resorting to intermediate heat storage) and the direct heat integration (i.e. heat exchanges between coexisting process streams) of batch processes. Tools and methods for the targeting of these two limiting cases of heat integration are proposed, and completed by the development and the application of an automatic design & optimization methodology using the Struggle genetic algorithm (GA). A brewery process is used to demonstrate the feasibility and the practical relevance of the proposed indirect heat integration models. The fluctuations of the process schedule and their effects on the optimal solutions are not modelled (the indirect heat integration is known to feature an inherently low sensitivity). The rescheduling opportunities are not searched for. For the indirect heat integration, fixed temperature/variable mass inventory heat storage units (HSUs) are applied. Two models of indirect heat recovery schemes (IHRSs) are proposed : one based on a closed heat storage system, another built around an open storage system suitable e.g. for food and beverages industries. The inequality constraints of the IHRS models are automatically met owing to an appropriate definition of the decision variables managed by the GA. A rough preadjustment of the mass balance equality constraints on HSUs is achieved by a preliminary stage of heat recovery (HR) maximization before actually minimizing the total batch costs (TBCs). Optimization runs and theoretical considerations on the generation & replacement strategy of Struggle demonstrate that the structural and the parametric variables cannot be efficiently optimized within a single level, resulting in a two-levels optimization scheme. The automatically designed closed storage IHRS solutions for the brewing process are as good as the solutions obtained by another author using a combinatorial method followed by a post-optimization stage. The open storage IHRS is 13 % cheaper while the HR increases by 12 %. Optimizing the IHRS on a one-week period (including the non-periodic start-up & shut-down phases) results in an even more realistic solution, featuring a significantly different trade-off between energy, HSU capacities and HEX areas. A GA based, two-levels optimization scheme is proposed for the design of direct batch heat exchanger networks (HENs). The HEN structures, managed by the upper-level GA, do not include stream splitting. The re-use of HEX units across time slices is a key issue and a methodology to specify the actually possible structural changes by repipe or resequence is proposed, accounting for the thermo-physical compatibility, chemical compatibility, and process schedule constraints. The optimum operation of an existing HEN during each time slice has been analysed and a sound solution procedure is proposed.

This work investigates the effects of carbon allocation on the emission intensities of low-carbon products cogenerated in facilities that co‐process biogenic and fossil feedstocks and apply the carbon capture utilization and storage technology. Thus, these plants simultaneously sequester CO2 and synthesize fuels or chemicals. We consider an integrated steel mill that injects biomass into the blast furnace, captures CO2 for storage, and ferments CO into ethanol from the blast furnace gas. We examine two schemes to allocate the CO2 emissions avoided [due to the renewable feedstock share (biomass) and CO2 capture and storage (CCS)] to the products of steel, ethanol, and electricity (generated through the combustion of steel mill waste gases): 1) allocation by (carbon) mass, which represents actual carbon flows, and 2) a free-choice attribution that maximizes the renewable content allocated to electricity and ethanol. With respect to the chosen assumptions on process performance and heat integration, we find that allocation by mass favors steel and is unlikely to yield an ethanol product that fulfills the Renewable Energy Directive (RED) biofuel criterion (65% emission reduction relative to a fossil comparator), even when using renewable electricity and applying CCS to the blast furnace gas prior to CO conversion into ethanol and electricity. In contrast, attribution fulfills the criterion and yields bioethanol for electricity grid intensities <180 gCO2/kWhel without CCS and yields bioethanol for grid intensities up to 800 gCO2/kWhel with CCS. The overall emissions savings are up to 27 and 47% in the near-term and long-term future, respectively. The choice of the allocation scheme greatly affects the emissions intensities of cogenerated products. Thus, the set of valid allocation schemes determines the extent of flexibility that manufacturers have in producing low-carbon products, which is relevant for industries whose product target sectors that value emissions differently. We recommend that policymakers consider the emerging relevance of co‐processing in nonrefining facilities. Provided there is no double-accounting of emissions, policies should contain a reasonable degree of freedom in the allocation of emissions savings to low-carbon products, so as to promote the sale of these savings, thereby making investments in mitigation technologies more attractive to stakeholders.

Role of CCS for Emission Reduction from Fertiliser and Cement Industry

Techno-economic analysis of power and hydrogen co-production by an IGCC plant with CO2 capture based on membrane technology

Development of oxygen transport membranes for coal-based power generation

Heat and power integration for hydrogen-fuelled Combined Cycle Gas Turbine (CCGT)

Aerosol-based emission, solvent degradation, and corrosion in post combustion CO2 capture