Solomon Aforkoghene Aromada

A standard CO₂ capture process is implemented in Aspen HYSYS, simulated, and evaluated based on available data from Fortum’s waste burning facility at Klemetsrud in Norway. Since amine-based CO₂ removal has high costs, the main aim is cost-optimizing. A simplified carbon-capture unit with a 20-m absorber packing height, 90% CO₂ removal efficiency, and a minimum approach temperature for the lean/rich amine heat exchanger (ΔT_min) of 10 °C was considered the base case simulation model. A sensitivity analysis was performed to optimize these parameters. For the base case study, CO₂ captured cost was calculated as 37.5 EUR/t. When the sensitivity analysis changes the size, the Power Law method adjusts the equipment cost. A comparison of the Enhanced Detailed Factor (EDF) and the Power Law approach was performed for all simulations to evaluate the uncertainties in the findings from the Power Law method. The optimums calculated for ΔT_min and CO₂ capture rate were 15 °C and 87% for both methods, with CO₂ removal costs of 37 EUR/t CO₂ and 36.7 EUR/t CO₂, respectively. With 19 m of packing height to absorber, the minimum CO₂ capture cost was calculated as 37.3 EUR/t and 37.1 EUR/t for the EDF and Power Law methods, respectively. Since there was a difference between the Power Law method and the EDF method, a size factor exponent derivation was performed. The derivation resulted in the following exponents: for the lean heat exchanger 0.74, for the lean/rich heat exchanger 1.03, for the condenser 0.68, for the reboiler 0.92, for the pump 0.88, and for the fan 0.23.

The performance of a plate heat exchanger (PHE), in comparison with the conventional shell and tube types, through a trade-off analysis of energy cost and capital cost resulting from different temperature approaches in the cross-exchanger of a solvent-based CO₂ capture process, was evaluated. The aim was to examine the cost reduction and CO₂ emission reduction potentials of the different heat exchangers. Each specific heat exchanger type was assumed for the cross-exchanger, the lean amine cooler and the cooler to cool the direct contact cooler’s circulation water. The study was conducted for flue gases from a natural-gas combined-cycle power plant and the Brevik cement plant in Norway. The standard and the lean vapour compression CO₂ absorption configurations were used for the study. The PHE outperformed the fixed tube sheet shell and tube heat exchanger (FTS-STHX) and the other STHXs economically and in emissions reduction. The optimal minimum temperature approach for the PHE cases based on CO₂ avoided cost were achieved at 4 °C to 7 °C. This is where the energy consumption and indirect emissions are relatively low. The lean vapour compression CO₂ capture process with optimum PHE achieved a 16% reduction in CO₂ avoided cost in the cement plant process. When the available excess heat for the production of steam for 50% CO₂ capture was considered together with the optimum PHE case of the lean vapour compression process, a cost reduction of about 34% was estimated. That is compared to a standard capture process with FTS-STHX without consideration of the excess heat. This highlights the importance of the waste heat at the Norcem cement plant. This study recommends the use of plate heat exchangers for the cross-heat exchanger (at 4–7 °C), lean amine cooler and the DCC unit’s circulation water cooler. To achieve the best possible CO₂ capture process economically and in respect of emissions reduction, it is imperative to perform energy cost and capital cost trade-off analysis based on different minimum temperature approaches.

We examined the cost implications of selecting six different types of heat exchangers as the lean/rich heat exchanger in an amine-based CO₂ capture process. The difference in total capital cost between different capture plant scenarios due to the different costs of the heat exchangers used as the lean/rich heat exchanger, in each case, is in millions of Euros. The gasketed-plate heat exchanger (G-PHE) saves significant space, and it saves considerable costs. Selecting the G-PHE instead of the shell and tube heat exchangers (STHXs) will save €33 million–€39 million in total capital cost (CAPEX), depending on the type of STHX. About €43 million and €2 million in total installed costs (CAPEX) can be saved if the G-PHE is selected instead of the finned double-pipe heat exchanger (FDP-HX) or welded-plate heat exchanger, respectively. The savings in total annual cost is also in millions of Euros/year. Capture costs of €5/tCO₂–€6/tCO₂ can be saved by replacing conventional STHXs with the G-PHE, and over €6/tCO₂ in the case of the FDP-HX. This is significant, and it indicates the importance of clearly stating the exact type and not just the broad classification of heat exchanger used as lean/rich heat exchanger. This is required for cost estimates to be as accurate as possible and allow for appropriate comparisons with other studies. Therefore, the gasketed-plate heat exchanger is recommended to save substantial costs. The CO₂ capture costs of all scenarios are most sensitive to the steam cost. The plate and frame heat exchangers (PHEs) scenario’s capture cost can decline from about €77/tCO₂ to €59/tCO₂ or rise to €95/tCO₂.

The first stage of any phase transition is a dynamic coupling of transport processes and thermodynamic changes. The free energy change of the phase transition must be negative and large enough to also overcome the penalty work needed for giving space to the new phase. The transition from an unstable situation over to a stable growth is called nucleation. Hydrate formation nucleation can occur along a variety of different routes. Heterogeneous formation on the interface between gas (or liquid) and water is the most commonly studied. A hydrate can also form homogeneously from dissolved hydrate formers in water, and the hydrate can nucleate toward mineral surfaces in natural sediments or a pipeline (rust). A hydrate particle’s critical size is the particle size needed to enter a region of stable growth. These critical sizes and the associated nucleation times are nanoscale processes. The dynamics of the subsequent stable growth can be very slow due to transport limitations of hydrate-forming molecules and water across hydrate films. Induction times can be defined as the time needed to reach a visible hydrate. In the open literature, these induction times are frequently misinterpreted as nucleation times. Additional misunderstandings relate to the first and second laws of thermodynamics and the number of independent thermodynamics variables. It is not possible to reach thermodynamic equilibrium in systems where hydrates form in a pipeline or in sediments. Finally, there are common misconceptions that only one type of hydrate will form. In a non-equilibrium situation, several hydrates will form, depending on which phases the hydrate formers and water come from. In this paper, we utilize a simple nucleation theory to illustrate nucleation and growth of some simple hydrates in order to illustrate the non-equilibrium nature of hydrates and the fast nucleation times. To illustrate this, we apply thermodynamic conditions for a real pipeline transporting natural gas from Norway to Germany. This specific example also serves as a case for illustration of the possible impact of rusty pipeline surfaces in kicking out water from the gas. Specifically, we argue that the tolerance limit for water concentration according to current industrial hydrate risk practice might overestimate the tolerance by a factor of 20 as compared to tolerance concentration based on adsorption on rust.

We have proposed a consistent thermodynamic scheme for evaluation of enthalpy changes of hydrate phase transitions based on residual thermodynamics. This entails obtaining every hydrate property such as gas hydrate pressure-temperature equilibrium curves, change in free energy which is the thermodynamic driving force in kinetic theories, and of course, enthalpy changes of hydrate dissociation and formation. Enthalpy change of a hydrate phase transition is a vital property of gas hydrate. However, experimental data in literature lacks vital information required for proper understanding and interpretation, and indirect methods of obtaining this important hydrate property based on the Clapeyron and Clausius-Clapeyron equations also have some limitations. The Clausius-Clapeyron approach for example involves oversimplifications that make results obtained from it to be inconsistent and unreliable. We have used our proposed approach to evaluate consistent enthalpy changes of hydrate phase transitions as a function of temperature and pressure, and hydration number for CH₄ and CO₂. Several results in the literature of enthalpy changes of hydrate dissociation and formation from experiment, and Clapeyron and Clausius-Clapeyron approaches have been studied which show a considerable disagreement. We also present the implication of these enthalpy changes of hydrate phase transitions to environmentally friendly production of energy from naturally existing CH₄ hydrate and simultaneously storing CO₂ on a long-term basis as CO₂ hydrate. We estimated enthalpy changes of hydrate phase transition for CO₂ to be 10–11 kJ/mol of guest molecule greater than that of CH₄ within a temperature range of 273–280 K. Therefore, the exothermic heat liberated when a CO₂ hydrate is formed is greater or more than the endothermic heat needed for dissociation of the in-situ methane hydrate.

Classical industrial hydrate risk evaluation schemes are commonly based on water dew‐point calculation. This method ignores another (new) route to hydrate formation based on adsorption of water onto rusty surfaces. Maximum allowable water contents in pure and mixtures of hydrate formers of Structures I and II hydrocarbons to avoid the risk of hydrate nucleation during pipeline transport have been studied using both the dew‐point method and the new approach of adsorption of water onto hematite (rust). The estimates from this study suggest that the new approach (adsorption of water onto the rusty internal walls of pipelines and equipment) dominates. Thus, this approach could have an impact on designing natural gas dehydration systems. Free energy analysis has also been performed to show which molecule forms hydrate first based on the combined first and second laws of thermodynamics in terms of Gibbs free energy. © 2018 American Institute of Chemical Engineers AIChE J, 65: 1097–1110, 2019