CO2 storage in depleted oil and gas fields in the Gulf of Mexico Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-20 Elif Agartan, Manohar Gaddipati, Yeung Yip, Bill Savage, Chet Ozgen
Depleted oil and gas reservoirs are one of the prime-candidate formations for geologic CO2 storage. Although both the geological structure and the physical properties of most of them have been extensively studied and characterized, there is limited data on the assessment of the CO2 storage capacity, especially in the offshore fields. The purpose of this study is to develop a high-level quantitative assessment of the CO2 volume that can be stored in depleted oil and gas fields in the Federal offshore regions of the Gulf of Mexico (GOM), both on a field-by-field and on a reservoir-by-reservoir basis. In this study, we simulated CO2 storage in 461 of the depleted oil and gas reservoirs (73 fields) among 3514 reservoirs (675 fields) in the GOM (2013 BOEM Reserves database). Based on the simulation results, we improved the Department of Energy (DOE) CO2 Storage Resource Estimate Equation to make more refined and accurate estimates of storable CO2 volumes. Newly revised efficiency factor (ERoil/gas) correlates better with hydrocarbon recovery factor (HCRF), which is found to be a strong indicator of the CO2 storage capacity of the reservoir. The higher HCRF results in higher ERoil/gas. The further investigations resulted in an improved, material balance-based correlation—which is called the Production-CO2 Storage Correlation—between cumulative production (free gas, oil and water) at reservoir conditions and CO2 storage volume at standard conditions. This relationship, which is unique for all three types of reservoirs (gas, oil and combination), allows for making direct estimates of CO2 storage volume using only existing production data. Application of these correlations to all of the depleted fields (3514 reservoirs) yields CO2 storage capacities of 4748 MMtons, and the CO2 storage capacity in all 1295 depleted and active fields (13,289 reservoirs) in the GOM calculated to be 21.57 Billion tons. If a 5000 psia surface injection pressure constraint was applied, these volumes would be reduced to 4075 MMtons for all depleted fields only and to 15.80 Billion tons for all depleted and active fields in the GOM. The production-CO2 storage correlations can be used to make more accurate CO2 storage volume estimates in all onshore and offshore depleted oil and gas fields.
The impact of gradational contact at the reservoir-seal interface on geological CO2 storage capacity and security Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Michael U. Onoja, Seyed M. Shariatipour
The implementation of CO2 storage in sub-surface sedimentary formations can involve decision making using relevant numerical modelling. These models are often represented by 2D or 3D grids that show an abrupt boundary between the reservoir and the seal lithologies. However, in an actual geological formation, an abrupt contact does not always exist at the interface between distinct clastic lithologies such as sandstone and shale. This article presents a numerical investigation of the effect of sediment-size variation on CO2 transport processes in saline aquifers. Using the Triassic Bunter Sandstone Formation (BSF) of the Southern North Sea (SNS), this study investigates the impact a gradation change at the reservoir-seal interface on CO2 sequestration. This is of great interest due to the importance of enhanced geological detail in reservoir models used to predict CO2 plume migration and the integrity of trapping mechanisms within the storage formation. The simplified strategy was to apply the Van Genutchen formulation to establish constitutive relationships for pore geometric properties, which include capillary pressure (Pc) and relative permeability (kr), as a function of brine saturation in the porous media. The results show that the existence of sediment gradation at the reservoir-seal interface and within the reservoir has an important effect on CO2 migration and pressure diffusion in the formation. The modelling exercise shows that these features can lead to an increase in residual gas trapping in the reservoir and localised pore pressures at the caprock’s injection point.
Impact of inner reservoir faults on migration and storage of injected CO2 Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Zhijie Yang, Tianfu Xu, Fugang Wang, Yanlin Yang, Xufeng Li, Ningning Zhao
CO2 geological storage (CGS) is an effective way to mitigate greenhouse gas emissions, and geological security is one of the most important issues in CGS. The faults distributed in geological formations make multi-layered reservoirs interconnected systems. A three-dimensional (3D) numerical model was established to evaluate the effects of inner reservoir faults on the CO2 migration and storage capacity of an actual CGS demonstration project in the Ordos Basin of China. The results show that the faults in the layered reservoir system could significantly affect the migration of injected CO2. The cross-layer faults at the bottom of the faulted reservoir could act as preferential passages between the upper and lower geological formations, causing the CO2 in the reservoir formation to move upward to adjacent layers rather than to lateral migration. CO2 migration along the inner-layer faults widely occurred at the top of the reservoir formation, decreasing the pressure accumulation and CO2 saturation around the injection well. Based on the simulation, CO2 will have migrated into the Heshanggou Formation after 300 years, and most of the CO2 will be trapped in the bottom sub-layers, with no CO2 intruding into the upper caprock. The spatial and temporal evolution of the injected CO2 was well presented for the faulted reservoir system, suggesting that the faults inside the multi-layered reservoir are beneficial to CGS.
Dynamic flowsheet simulation for chemical looping combustion of methane Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Johannes Haus, Ernst-Ulrich Hartge, Stefan Heinrich, Joachim Werther
In a Chemical Looping Combustion system, the fuel and air reactors are strongly coupled because of chemical reactions in both and the circulation of solid oxygen carrier between them. To capture the effects inside the system, a novel dynamic flowsheet simulation environment for solids processes is applied to Chemical Looping Combustion of methane. Flowsheet simulation is a tool for process analysis and optimization covering multiple process units and flows in a system. An experimental 25 kWth pilot plant is operated, and all of its process units are modeled. The modeling comprises three fluidized bed reactors, two operating in bubbling fluidized bed condition and one as a circulating fluidized bed riser. A cyclone is used for gas-solid separation after the air reactor. The loop seals ensure gas sealing between the reactors. Fluid mechanics inside the systems are modeled with empirical and semi-empirical correlations, to enable fast calculations. This approach becomes handy when long-term dynamic effects like abrasion, start-up, or shut-down procedures as well as load changes are to be modeled. Chemical reactions for a gaseous fuel and their implications on gas flows were implemented. In addition, oxidation and reduction of the solid oxygen carrier in the three reactors were part of the simulation. To validate the simulation results, the pilot plant was operated with methane as fuel. Gas measurements were taken after both stages of the fuel reactor. Additionally, solid samples were drawn from the hot facility to examine the oxidation state of the carrier, when fuel is introduced. A transient simulation of plant operation over a total runtime of 40 min reveals that the solids inventories of the fluidized bed reactors in the system need only 30 s in the present case to reach a new steady state after a load change. If the oxidation and reduction reactions of the oxygen carrier are taken into account, however, this response time extends dramatically to several hundreds of seconds, which can also be seen in the experimental campaigns. The simulation of such a system behavior requires a powerful simulation tool for flowsheeting, which has been found here in the dynamic simulation framework.
Analysis of the contribution of CCS to achieve the objectives of Mexico to reduce GHG emissions Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 David Castrejón, Alan M. Zavala, Jesús A. Flores, Marco Polo Flores, Diana Barrón
Mexico has a strong commitment to reduce its greenhouse gas (GHG) emissions. The electrical and the industrial sectors have been the second and third largest contributors to GHG emissions–excluding fugitive emissions-. This paper analyzes the potential contributions of Carbon Capture and Storage (CCS) systems on the electrical sector, as well as the participation of the cement, metal and chemical industries. This study was carried out using a computational mathematical model, the MEM70, which is a partial equilibrium model that represents the Mexican energy system. It was found that, even considering energy efficiency measures, a high penetration of electric vehicles and the electrical sector with high participation of low carbon emission technologies such as renewable and nuclear sources. Further, it is necessary to implement CCS to achieve the goal for reducing national greenhouse gas emissions.
Cross impact of CO2 phase and impurities on the corrosion behavior for stainless steel and carbon steel in water-containing dense CO2 environments Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Minghe Xu, Qian Zhang, Zhe Wang, Jianmin Liu, Zheng Li
A series of study was conducted to investigate the corrosion behavior of 2Cr13 stainless steel and X65 carbon steel exposed to water-saturated and water-unsaturated dense CO2 environments with SO2 and O2 impurities in the conditions of 25 °C and 50 °C, 8 MPa. Each test lasted for 48 h. The cross impacts of CO2 phase (liquid phase and supercritical phase), water contents and steel types on the corrosion behavior were elaborately discussed. In water-saturated impure dense CO2 with SO2, SO2/O2 systems, the impacts of single impurity of SO2 and multiple impurities of SO2 and O2 on accelerating general corrosion for both 2Cr13 and X65 steels was much stronger in the supercritical CO2 system than in the liquid CO2 system. At water-unsaturated conditions, 2Cr13 stainless steel exhibited better resistance to the general corrosion attack in liquid and supercritical CO2 with SO2 in comparison with X65 carbon steel, but suffered high risk of localized corrosion in liquid CO2 mixtures. The 2Cr13 and X65 steels could bear higher amounts of water in supercritical CO2 with SO2 systems (∼1300 ppm H2O) than in the liquid CO2 with SO2 systems (<300 ppm H2O).
Qualitative and quantitative experimental study of convective mixing process during storage of CO2 in heterogeneous saline aquifers Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Amir Taheri, Ole Torsæter, Erik Lindeberg, Nanji J. Hadia, Dag Wessel-Berg
CO2 dissolution is considered as one of the most promising mechanisms for trapping of free-phase CO2 into brine. It causes an increased density of the brine and initiation of gravitational instability that eventually leads to density-driven natural convection in saline aquifers. Correct estimation of the onset time for convection and the rate of dissolution of CO2 into brine is important because the timescale for dissolution corresponds to the timescale over which free-phase CO2 has a chance to leak out. The gravitational instability of a diffusive boundary layer in porous media has been studied in several papers in recent years, but there are few works about the behavior of density-driven natural convection mechanism in heterogeneous saline aquifers. Barriers such as shales and calcites layers are common types of heterogeneities in geological formations that are important in the fluid flow. Despite the recognized importance of convective dissolution in these heterogeneous geological formations, there is no experimental data available for studying the accelerated mass transfer rate of CO2 into these media. In this paper, we investigated the effect of the regular distribution of barriers on the rate of dissolution of CO2 into water and geometries of convection fingers. A series of experiments were performed using a precise experimental set-up with barrier heterogeneous Hele-Shaw cell geometries and by using CO2 and water. The approach and procedure for performing the experiments give us this opportunity to have both qualitative (images and movies) and quantitative (amount of the dissolved CO2 into water) data at the same time. The behavior of convection pattern after onset time and the effect of system properties on the behavior of convective mixing process will be presented and discussed. Moreover, some speeded-up movies from the experiments that are suitable for improving public awareness of the problem have been uploaded on the internet platform. Lastly, the relationships between dissolution flux after onset time for convection and barrier properties are discussed.
Effect of CO2 phase on its water displacements in a sandstone core sample Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Ebraheam Al-Zaidi, James Nash, Xianfeng Fan
CO2 injection into underground formations can reduce CO2 emissions, enhance hydrocarbon and methane recovery, and extract geothermal heat. As the pressure and temperature vary in subsurface formations, the injected CO2 can be in gas, liquid and supercritical phase. The change in CO2 phase is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on injectivity, displacement, migration, storage capacity and integrity of CO2 processes. This study was designed to investigate the effect of CO2 phase, at different injection rates, on the dynamic pressure evolution and the CO2 displacement performance during CO2 injection into a water-saturated sandstone core sample. The results indicate that CO2 phase significantly affects the differential pressure profile and water production profile. The differential pressure profiles measured from the displacement of supercritical CO2 and gas CO2 were significantly different from those measured from liquidCO2 displacements, particularly before CO2 breakthrough. Gas and supercriticalCO2 injection gave a water production rate much higher than the CO2 injection rate at early stages. Liquid CO2 injection yielded a water production rate similar to the CO2 injection rate. This may indicate that the injection of ScCO2or GCO2 (under a pressure higher than 60 bar) could give a high and quick oil production rate. The highest water recovery was obtained after the injection of 0.85, 1.08 and 2.32 pore volumes of scCO2, gCO2, and LCO2, respectively. The residual water saturations for the three CO2 phases were in the range of 30–33% while the endpoint relative permeability was in the range of 18–21%. The endpoint relative permeabilities for gas and liquid CO2 were very similar and higher than that of supercritical CO2 under our experimental conditions. The increase in injection rate caused a slight increase in the endpoint relative permeabilities for the three CO2 phases.
Chemical-looping combustion of synthetic biomass-volatiles with manganese-ore oxygen carriers Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Patrick Moldenhauer, Sebastian Sundqvist, Tobias Mattisson, Carl Linderholm
Flexible operation of post-combustion CO2 capture at pilot scale with demonstration of capture-efficiency control using online solvent measurements Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Paul Tait, Bill Buschle, Kris Milkowski, Muhammad Akram, Mohamed Pourkashanian, Mathieu Lucquiaud
Flexible post-combustion carbon capture and storage (CCS) has the potential to play a significant part in the affordable decarbonisation of electricity generation portfolios. PCC plant operators can modify capture plant process variables to adjust the CO2 capture level to a value which is optimal for current fuel cost, electricity selling price and CO2 emissions costs, increasing short-term profitability. Additionally, variation of the level of steam extraction from the generation plant can allow the capture facility to provide additional operating flexibility for coal-fired power stations which are comparatively slow to change output. A pilot-scale test campaign investigates the response of plant operating parameters to dynamic scenarios which are designed to be representative of pulverised coal plant operation. Online sensors continuously monitor changes in rich and lean solvent CO2 loading (30%wt monoethanolamine). Solvent loading is likely to be a critical control variable for the optimisation of flexible PCC operation, and since economic and operational boundaries can change on timescales 30 min or shorter, the development of methods for rapid, continuous online solvent analysis is key. Seven dynamic datasets are produced and insights about plant response times and hydrodynamics are provided. These include power output maximisation, frequency response, power output ramping and a comparison between two plant start-up strategies. In the final dynamic operating scenario, control of CO2 capture efficiency for a simple reboiler steam decoupling and reintroduction event is demonstrated using only knowledge of plant hydrodynamics and continuous measurement of solvent lean loading. Hot water flow to the reboiler is reduced to drop the capture efficiency. The “target” value for the minimum capture efficiency in the scenario was set at 30%, but a minimum CO2 capture efficiency of 26.4% was achieved. While there remains scope for improvement this represents a significant practical step towards the control of capture plant using online solvent concentration and CO2 measurements, and the next steps for its further development are discussed.
Cost-optimal design of pressure-based monitoring networks for carbon sequestration projects, with consideration of geological uncertainty Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Hoonyoung Jeong, Alexander Y. Sun, Xiaodong Zhang
CO2 stripping from ionic liquid at elevated pressures in gas-liquid membrane contactor Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Stepan Bazhenov, Alexander Malakhov, Danila Bakhtin, Valery Khotimskiy, Galina Bondarenko, Vladimir Volkov, Mahinder Ramdin, Thijs J.H. Vlugt, Alexey Volkov
Selective exhaust gas recirculation in combined cycle gas turbine power plants with post-combustion CO2 capture Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Laura Herraiz, Eva Sánchez Fernández, Erika Palfi, Mathieu Lucquiaud
In the context of the process intensification of Post-combustion Carbon Capture (PCC), Selective Exhaust Gas Recirculation (SEGR) in Natural Gas-fired Combined Cycle (NGCC) plants, a concept where CO2 is selectively recycled to increase concentration and reduce flow rates of the flue gas, is analysed. SEGR operated either in parallel or in series with a downstream PCC system increases CO2 concentration beyond 14 vol% and maintains oxygen levels in the combustor to approximately 19 vol%, well above the 16 vol% limit reported for non-selective Exhaust Gas Recirculation (EGR). Process modelling shows that the current class of gas turbine engines can operate without a significant deviation in the compressor and in the turbine performance. Compressor inlet temperature and CO2 concentration in the working fluid are the two critical parameters affecting the gas turbine net power output and efficiency. A higher turbine exhaust temperature allows the generation of additional steam in the HRSG. This results in an increase in net power output of approximately 42 MW (5.2%) and 18 MW (2.3%), and in net thermal efficiency of 0.55%point and 0.83%point, for the investigated configurations with SEGR in parallel and SEGR in series, respectively. With 30 wt% aqueous monoethanolamine scrubbing technology, SEGR leads to operation and cost benefits. SEGR in parallel with 70% recirculation, 97% selective CO2 transfer efficiency and 96% PCC efficiency results in a reduction of 46% in packing volume and 5% in specific reboiler duty, compared to air-based combustion CCGT with PCC, and of 10% in packing volume and 2% in specific reboiler duty, compared to 35% EGR. SEGR in series operating at 95% selective CO2 transfer efficiency and 32% PCC efficiency results in a reduction of 64% in packing volume and 7% in specific reboiler duty, compared to air-based CCGT with PCC, and of 40% in packing volume and 4% in specific reboiler duty, compared to 35% EGR. On selecting a technology for SEGR applications, CO2 selectivity, pressure drop and heat transfer flow rate are the operating parameters with a larger effect on the power plant performance with SEGR. It is important to minimise oxygen leakages from the air into the flue gas, minimise heat transfer that would otherwise increase CO2-enriched air temperature at compressor inlet, and minimise pressure drop, e.g. a 1 kPa pressure drop results in gas turbine derating of 2 MW (0.7%).
Early-stage risk evaluation processes and outcomes for Aquistore project Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-19 Ken Hnottavange-Telleen
The Ginninderra CH4 and CO2 release experiment: An evaluation of gas detection and quantification techniques Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-15 Andrew Feitz, Ivan Schroder, Frances Phillips, Trevor Coates, Karita Neghandhi, Stuart Day, Ashok Luhar, Sangeeta Bhatia, Grant Edwards, Stefan Hrabar, Emili Hernandez, Brett Wood, Travis Naylor, Martin Kennedy, Murray Hamilton, Mike Hatch, John Malos, Mark Kochanek, Peter Reid, Joel Wilson, Nicholas Deutscher, Steve Zegelin, Robert Vincent, Stephen White, Cindy Ong, Suman George, Peter Maas, Sean Towner, Nicholas Wokker, David Griffith
CO2 capture in ethanol distilleries in Brazil: Designing the optimum carbon transportation network by integrating hubs, pipelines and trucks Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-06 Fabio T.F. da Silva, Francielle M. Carvalho, Jorge Luiz G. Corrêa Jr., Paulo R. de C. Merschmann, Isabela S. Tagomori, Alexandre Szklo, Roberto Schaeffer
The growing importance of negative emission technologies in the energy sector for a “well-below 2 °C” world by 2100 seems to be a great opportunity for biological carbon capture and storage (BECCS) in the Brazilian sugarcane ethanol industry, given the low capture costs of the CO2 produced during the alcoholic fermentation process and the potential to store and use the CO2 for Enhanced Oil Recovery (EOR) in mature oil fields in the country. Notwithstanding, previous scientific studies indicated high transport infrastructure costs as a major constraint for the economic feasibility of exploiting this potential. This work developed and applied a methodology to design an optimal sugarcane ethanol BECCS CO2 network (the baseline) together with two alternative concepts: one considering an inter-modal network of road and pipeline transport and another with a multiple-hub system. The results for the system’s abatement costs, including sensitivity analyses for the best- and worst-case scenarios, ranged between 32 and 87 US$/t of CO2. The road modal choice cut-off range applies to distilleries with a CO2 annual production under 150–200 kt and further than 250–300 km from the hub. For the reference case, 70 out of the 236 distilleries opted for the road modal connection to the hub.
Indirect ocean capture of atmospheric CO2: Part II. Understanding the cost of negative emissions Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-07 Matthew D. Eisaman, Jessy L.B. Rivest, Stephen D. Karnitz, Charles-François de Lannoy, Arun Jose, Richard W. DeVaul, Kathy Hannun
Fate of transition metals during passive carbonation of ultramafic mine tailings via air capture with potential for metal resource recovery Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-03-06 Jessica L. Hamilton, Siobhan A. Wilson, Bree Morgan, Connor C. Turvey, David J. Paterson, Simon M. Jowitt, Jenine McCutcheon, Gordon Southam
The effect of argon contamination on interfacial tension, diffusion coefficients and storage capacity in carbon sequestration processes Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-28 Gregor Kravanja, Željko Knez, Maša Knez Hrnčič
In this study, the effect of argon as a co-contaminant in a CO2 stream on interfacial tension, diffusion coefficients and storage capacity was experimentally determined under conditions relevant to carbon sequestration, using the pendant drop method. Interfacial properties affect primary capillary trapping mechanisms when CO2 is injected since they set a limit to storage capacity in a geological formation. A strong increase in the isothermal interfacial tension at 45 °C and up to 20 MPa was observed with an increase in Ar co-contamination from 5 vol.% up to 100 vol.%. Since Ar content is present in small concentrations in most injected CO2 streams, we focused on measuring brine-CO2 interfacial tension and brine mixture (CO2 and Ar) interfacial tension, with 5 vol.% and 10 vol.% of argon content at pressures from 7.5 MPa up to 40 MPa and in the temperature range from 40 °C to 80 °C, which has not previously been investigated and can be considered more oriented to real-world conditions for carbon sequestration. It was found that storage capacity decreased significantly from a scenario where pure CO2 was injected, down to a scenario where 5 vol.% and 10 vol.% Ar were co-injected into the CO2 stream. Additionally, the effect of other common impurities in CO2 streams on interfacial properties and storage capacity is discussed. In order to evaluate the risk of CO2 diffusion loss through a cap rock, we measured the diffusion coefficients of geological water in the injected fluid. It was found that the diffusion coefficients of water in Ar are higher in comparison to those of water in CO2. Small quantities of salt in water had a minor effect on the diffusion coefficients of brine in supercritical CO2. Experimentally obtained diffusion coefficients (Dab) were correlated to obtain the effective diffusion coefficient (Deff). It was found that, in the case of co-injection of Ar with CO2, the diffusive gas breakthrough could be enhanced.
Uncertainty quantification of CO2 storage using Bayesian model averaging and polynomial chaos expansion Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-28 Wei Jia, Brian McPherson, Feng Pan, Zhenxue Dai, Ting Xiao
Carbon sequestration in oil reservoirs and deep saline formations may be accomplished by many different trapping mechanisms. Use of CO2 for Enhanced Oil Recovery (CO2-EOR) leads to CO2 in three distinct phases, including CO2 dissolved in oil, CO2 dissolved in water (aqueous) and/or supercritical CO2. We evaluated the total amount of stored CO2 as well as the amount of CO2 in each phase for an active CO2-EOR site in western Texas. Three-phase relative permeability and associated hysteresis are two major sources of model uncertainty. Both are difficult to measure and are usually predicted by interpolation models. Instead of using arbitrary interpolation models, we used a model-averaging method based on Bayesian inference to estimate integrated model uncertainty for 12 alternative models. Moreover, given the uncertainty of intrinsic rock properties including permeability and porosity, uncertainty quantification (UQ) of these parameters is also necessary for forecasting CO2 storage capacity. Thus, results of this study provide uncertainty based on both model and data uncertainty. Conventional Monte Carlo methods with geocellular simulations are computationally expensive. We applied a Polynomial Chaos Expansion (PCE) methodology instead, to reduce computational requirements while minimizing the loss of accuracy. Geostatistical techniques were applied to generate stochastic realizations based on well logs and seismic survey data. For the Texas case study, we developed a systematic approach to quantify overall uncertainty, including both model uncertainty and parameter uncertainty. The approach was applied to forecast results at three important time steps, the end of the 30-year CO2-EOR injection period, the end of the 20-year post EOR CO2 injection period, and the end of the 50-year monitoring period. Results suggest that oil solubility dominates CO2 trapping and aqueous solubility has the least relative importance with respect to trapping (storage). Predictions of model averaging preserved the general pattern and captured differences among alternative models. CO2 storage of the reference model was within one standard deviation of predictions of model averaging. Estimated relative error between forecasted CO2 storage and the reference model are 0.8%, 7.4%, and 6.1% at three selected time steps. By the end of simulation, estimated CO2 storage in five selected layers in oil, supercritical, and aqueous phases are 3.4 ± 0.3 million tonnes, 2.0 ± 0.25 million tonnes, and 0.24 ± 0.04 million tonnes, respectively.
Assessment of the impact of CO2 storage in sandstone formations by experimental studies and geochemical modeling: The case of the Mesohellenic Trough, NW Greece Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-28 Nikolaos Koukouzas, Zacharenia Kypritidou, Gemma Purser, Christopher A. Rochelle, Charalampos Vasilatos, Nikolaos Tsoukalas
Impact of CO2 injection on the hydro-mechanical behaviour of a clay-rich caprock Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-28 Valentina Favero, Lyesse Laloui
The safe storage of CO2 in deep reservoir units requires an efficient sealing of the overlaying caprock. The acidic environment caused by the dissolution of CO2 into the pore fluid can induce changes in the microstructure of the material over the long term and might consequently impact its retention capabilities through changes in the pore size and pore connectivity. In the first part of this paper, the impact of a low pH environment on some of the physical properties, such as grain density, void ratio and dominant entrance pore size, and on the retention capacity of a shaly caprock representative material, i.e., Opalinus Clay shale, is investigated by using an HCl solution inducing a pH = 3. The results show that grain density, dominant entrance pore size and void ratio are not significantly affected by the contact with a low pH environment in the considered period. Similar conclusions can be drawn for the retention capacity because the air entry value appears to be the same for treated and non-treated material. Subsidence and mechanical failure of the caprock are among the issues related to CO2 storage technology. The second part of the paper is dedicated to the analysis of the impact of CO2 injection on the mechanical behaviour of the Opalinus Clay shale. CO2 injection under constant stress conditions with consideration of different overconsolidation ratios is conducted to take into account different loading paths that could be experienced in situ by the caprock. The results show that the injection of CO2 induces the development of volumetric strains of less than 0.1%. Lower strains are measured when the material is overconsolidated; this result can be related to the fact that the material structure is more prone to collapse when it is found in normally consolidated conditions. The observed vertical displacements can be partially caused by desaturation effects induced by the differential pressure between CO2 and pore water, together with double layer effects induced by the CO2 diffusing along the height of the specimen. The impact of CO2 injection on the hydro-mechanical properties of the material is also analysed. The findings suggest that the diffusion of CO2 into the shale does not impact the hydro-mechanical properties of the material because no significant change in oedometric modulus, coefficient of consolidation, secondary compression coefficient, poromechanical parameters and hydraulic conductivity are highlighted after the injection of CO2.
Assessment of a membrane contactor process for pre-combustion CO2 capture by modelling and integrated process simulation Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-27 Muhammad Usman, Magne Hillestad, Liyuan Deng
A membrane contactor process for pre-combustion CO2 capture from shifted synthesis gas originated from IGCC power plant is assessed from the technical and economical point of views. The process is designed as pressure swing absorption and desorption in a closed loop. The design basis for process simulation were synthesis gas containing CO2 and H2 only, and the CO2 capture efficiency was fixed to 90%. The CO2 gas was absorbed in ionic liquid [bmim][TCM] inside a hydrophobic, porous hollow fibre membrane contactor. One-dimensional mathematical model of membrane contactor developed in MATLAB was integrated to the process simulation software (HYSYS) through Cape-Open simulation compiler. The energy evaluation of this process revealed that compressors are the most energy demanding process equipment. The specific energy requirement for this process is estimated 0.75 MJ/kg CO2. A parametric study was also performed to analyse the effect of CO2 concentration in feed gas and liquid to gas ratio. The capital cost investment and total operating costs of CO2 capture unit were also evaluated. The capital investment required for capturing 0.14 M ton CO2/year including CO2 compression is 47.4 M $, and the operating cost per year is 9.04 M $. The membrane absorber contributed about 39% to total investment cost. The specific cost of this capture unit is calculated to be 87 $/ton CO2.
Fate of sulfur in chemical looping combustion of gaseous fuels using a copper-based oxygen carrier Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-26 Robert F. Pachler, Karl Mayer, Stefan Penthor, Mario Kollerits, Hermann Hofbauer
The development of the chemical looping combustion technology for gaseous fuels has reached a point where it has been demonstrated in several pilot units for several thousands of hours using a variety of oxygen carriers. So far, a lot of experimental work was focused on fuel conversion performance and life time of oxygen carrier particles. In addition to the general performance of an oxygen carrier regarding fuel conversion, it is of special interest how it interacts with fuel impurities or contaminants like sulfur. Here, it is not only of interest if and how impurities affect fuel conversion performance, but also in which composition and in which reactor stream (air reactor or fuel reactor) they leave the CLC system. This knowledge is of great importance when it comes to the requirements of exhaust gas treatment facilities in large scale units. In the present study, the fate of sulfur in chemical looping combustion has been investigated in a 120 kWth pilot unit consisting of two interconnected circulating fluidized beds using a copper based oxygen carrier prepared by impregnation on an inert alumina support. Natural gas from the grid, originally without sulfur, was used as fuel. To investigate the influence of sulfur, H2S has been added to the fuel stream up to a concentration of 2000 ppmv. In order to close the mass balance of sulfur, the exhaust gas streams of air and fuel reactor are analyzed against H2S and SO2. Further, solid samples of the oxygen carrier particles were taken on a regular basis to investigate potential interaction of sulfur with the particles. The contribution shows how sulfur affects the general fuel conversion performance of the oxygen carrier as well as how much H2S is converted to SO2 and in which exhaust gas stream it leaves the reactor system. Measurements were performed for several temperatures in the range of 800–850 °C.
Experimental study of gravitational mixing of supercritical CO2 Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-25 Dennis L. Newell, J. William Carey, Scott N. Backhaus, Peter Lichtner
CO2 injection into saline aquifers for sequestration will initially result in buoyant supercritical (sc)CO2 trapped beneath the caprock seal. During this period, there is risk of CO2 migration out of the reservoir along wellbore defects or fracture zones. Dissolution of the scCO2 plume into brine results in solubility trapping and reduces this risk, but based on diffusion alone, this mechanism could take thousands of years. Gravitational (density-induced) mixing of CO2-saturated brine is shown to significantly accelerate this process in computational studies, but few experimental efforts have confirmed the phenomenon. Here, constant-pressure, 3-dimensional bench-scale experiments used the mass of added water to quantify the mass transfer of scCO2 into water-saturated porous media at 40–90 °C and 20 MPa, with Rayleigh numbers from 2093 to 16256. Experiments exhibit a period of 7–35X enhancement in mass transfer rates over diffusion, interpreted as gravitational mixing. Convective CO2 flux ranges from 1.6 × 10−2 to 4.8 × 10−3 mol s−1 m−2 in the experiments. Results are used to benchmark a computational model using PFLOTRAN. Experiments show an early diffusive onset period that is shorter with rates much higher than predicted by models and observed in analog experiments. Both experiments and models show convective mixing periods and similar overall rates of CO2 mass transfer.
3D architecture of the Aquistore reservoir: Implications for CO2 flow and storage capacity Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-25 D.J. White
Quantitative assessment of the Aquistore CO2 storage reservoir has been conducted using a 30 km2 3D seismic volume and a suite of well logs. 3D porosity was calculated using acoustic impedance from model-based seismic inversion and a log-based porosity-impedance relation. The reservoir has a mean thickness of 219 m ±ơ = 3% comprising 51% of pay. Strata dip at ∼1.75% SSE and include a prominent SSE-NNW structural fabric dominated by a ridge that corresponds to a Precambrian basement fault and overlying flexure. Porosity maps for Black Island and Deadwood reservoir zones show mean interval porosities of 0.071 ± ơ = 18% and 0.075 ± ơ = 9%, respectively with a weak degree of directionality that is sub-parallel to the strong NNW-SSE structural trends. Lateral spread of injected CO2 will be strongly affected by the NNW-trending structural relief and bulk porosity/permeability trends. Local topographic channels may control CO2 flow particularly when injection rates are low and local closed topographic structures may constitute traps for CO2. CO2 static capacity estimates from well-based mean values are less than comparable seismic-based estimates by <15% due to porosity differences and <5% due to thickness differences. Variations in the Deadwood thickness of up to 25 m from the mean value would have resulted in capacity estimate differences of up to 25% if an alternate well location had been chosen.
Assessing the potential to use repeated ambient noise seismic tomography to detect CO2 leaks: Application to the Aquistore storage site Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-22 Anna L. Stork, Claire Allmark, Andrew Curtis, J.-Michael Kendall, Don J. White
The Aquistore project in Saskatchewan, Canada provides carbon dioxide (CO2) storage for the world's first combined commercial power plant and carbon capture and storage (CCS) project. CO2 has been injected at a depth of 3.2 km since April 2015 and a permanent near surface geophone array provides passive seismic monitoring. The ability to identify any containment breach is a vital part of risk management and reduction for CO2 storage sites. We therefore investigate the potential to monitor seismic velocity changes following a hypothetical leak of CO2 from the reservoir using passive monitoring methods. We estimate the expected shear-wave velocity change with CO2 saturation, and using data from the geophone array we investigate whether ambient noise interferometry (ANI) and a tomographic inversion for Rayleigh wave group-velocity maps could provide a suitable CO2 leakage detection tool. To assess the repeatability of the method, we conduct, for the first time, a time-lapse ambient noise tomography survey of a CO2 storage site to cover time periods preceding and following injection start-up. Sensitivity analysis results indicate that usable surface wave data derived from the current array configuration are sensitive to depths of ∼400 m and shallower. We do not expect to observe any changes due to CO2 migration at such shallow depths and the estimated seismic velocities pre- and post-injection agree to within 60 m s−1, which is on the order of double the predicted velocity change with CO2 saturation. Therefore, due to uncertainties in travel-time picks (5–15%) and variations in the obtained velocity structure between consecutive days (up to 20%), we would be unable to resolve the expected seismic velocity change with an influx of CO2 at 400 m (∼3–4%). Additionally, the noise source variability does not allow stable velocity estimates to be made in the time-frame of currently-available data. Consequently, in the event of a CO2 leak at the Aquistore site, using the standard ambient noise analysis methods applied herein, Rayleigh wave tomography could be deployed to detect velocity changes due to CO2 saturation only if (a) a wider aperture surface array was in place to allow longer period surface waves to be used, providing sensitivity at greater depths, (b) arrival times of interferometrically-synthesised surface waves could be picked with increased accuracy, and (c) there is stability of the noise source distribution between repeated surveys. However, a map of three-dimensional near surface velocities, as obtained in this study, could nevertheless be useful for near surface static corrections when using active-source seismic reflection surveys to image and monitor the reservoir. More generally, further similar studies are required to assess the applicability of ANI for leak detection at other CO2 storage sites.
Investigation on the thermodynamic calculation of a 35 MWth oxy-fuel combustion coal-fired boiler Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-22 Zewu Zhang, Xiaoshan Li, Cong Luo, Liqi Zhang, Yongqing Xu, Yongfu Wu, Ji Liu, Yansong Duan, Chuguang Zheng
Oxy-fuel combustion technology is one of the most promising technologies for CO2 capture from coal-fired power plants and is remarkably characterized by the recycled flue gas (RFG). RFGs and pure oxygen are substitute for air, which alter the thermodynamics and heat transfer features for an oxy-fuel combustion coal-fired boiler. Hence, conventional thermodynamic calculation method for air combustion need to be improved for oxy-fuel combustion. This study primarily proposed a modified thermodynamic calculation method, which is subsequently verified by the experimental data for a 35 MWth coal-fired boiler under oxy-fuel combustion with dry and wet recycle modes. Validation results indicate that the modified method could predict the temperatures well in the main heating surfaces of the boiler for oxy-fuel combustion. Given the fine distinction between calculated and experimental temperatures for the main heating surfaces, several key parameters in the main heating surfaces are corrected to improve the precision of the corrected method. Compared with air combustion, the fouling factors for oxy-fuel wet recycle and dry recycle increase, while the effective coefficients and ash deposition coefficients for oxy-fuel combustion reduce. Notably, the utilization coefficients for oxy-fuel are relative to those for air combustion. The heat transfer features in the main heating surfaces are also discussed. Consequently, heat transfer is mainly controlled by the radiative heat transfer of flue gas in the furnace and is determined by the heat capacity of flue gas in the horizontal and vertical heating surfaces under oxy-fuel combustion.
Numerical analysis of mixed-mode rupture propagation of faults in reservoir-caprock system in CO2 storage Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-23 Sohrab Gheibi, Victor Vilarrasa, Rune M. Holt
Injection-induced seismicity and caprock integrity are among the most important concerns in CO2 storage operations. Understanding and minimizing fault/fracture reactivation in the first place, and rupture growth/propagation beyond its surface afterwards, are fundamental to achieve a successful deployment of geologic carbon storage projects. Rock fracture mechanics provides useful concepts to study the propagation of discontinuities such as pre-existing faults and fractures. In this paper, we aim at developing a methodology to investigate the rupture propagation likelihood of faults/fractures inside a reservoir and its surrounding (including the caprock) as a result of reservoir pressurization. In this methodology, mode I (tensile) and mode II (shear) stress intensity factors of a given fault/fracture are calculated based on Linear Elastic Fracture Mechanics. A fault/fracture can propagate either in mode I, mode II or a combination of both (also called mixed-mode) based on the comparison of the stress intensity factors and fracture toughness. The proposed methodology, which has been embedded into a hybrid Finite Element Method-Discrete Element Method in-house code called MDEM, has the capability to obtain the direction of mode I and mode II rupture in front of a fault/fracture tip. Two coefficients are defined as stress intensity paths (κ) for a fault/fracture, as the change of stress intensity factors for the two failure modes of a given discontinuity per unit pore pressure change of the reservoir after injection. Based on these stress intensity path coefficients, a relationship is given to calculate the threshold pressure buildup above which the two propagation modes may occur. We use the proposed methodology to investigate the rupture growth likelihood of faults in and around a closed reservoir due to its pressurization. Simulation results indicate that mode I failure is likely to occur inside the reservoir for faults with low dip angle in compressional stress regimes. However, the initiated mode I failure may not have the chance to grow upwards because the minimum principal is in the vertical direction and thus, the initiated rupture tends to rotate and grow horizontally. In contrast, mode I rupture is likely to occur in the caprock for faults with high dip angle in extensional stress regimes. The initiated rupture may grow upwards if the newly created fracture becomes hydraulically connected with the reservoir. We find that mode II rupture is not likely to occur in any of the investigated scenarios. Simulation results show that the coefficients of the stress intensity factors depend on the faults location, dipping angle, fault length, presence of other faults, reservoir aspect ratio and reservoir and caprock stiffness.
Integration of solid oxide fuel cell (SOFC) and chemical looping combustion (CLC) for ultra-high efficiency power generation and CO2 production Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-21 Vincenzo Spallina, Pasquale Nocerino, Matteo C. Romano, Martin van Sint Annaland, Stefano Campanari, Fausto Gallucci
This work presents a thermodynamic analysis of the integration of solid oxide fuel cells (SOFCs) with chemical looping combustion (CLC) in natural gas power plants. The fundamental idea of the proposed process integration is to use a dual fluidized-bed CLC process to complete the oxidation of the H2-CO-rich anode exhausts from the SOFC in the CLC fuel reactor while preheating the air stream to the cathode inlet temperature in the CLC air reactor. Thus, fuel oxidation can be completed in N2-free environment without the high energy and economic costs associated to O2 production, avoiding at the same time the high temperature and high cost heat exchanger needed in conventional SOFC plants for air preheating. In the proposed configurations, the CLC plant is operated at mild conditions (atmospheric pressure and temperature in the range of 700–800 °C), already demonstrated in several pilot plants. Two different scenarios have been investigated: in the first one, the SOFC is designed for large-scale power generation (100 MWLHV of heat input), featuring a heat recovery steam cycle and CO2 capture for subsequent storage. In the second scenario, the system is designed for a small-scale plant, producing 145 kg/h of pure CO2 for industrial utilization, as a possible early market application. The main parameters affecting the plant performance, i.e. SOFC voltage (V) and S/C ratio at SOFC inlet, have been varied in a sensitivity analysis. Three different materials (Ni, Fe and Cu-based) are also compared as oxygen carriers (OCs) in the CLC unit. The integrated plant shows very high electric efficiency, exceeding 66%LHV at both small and large scale with a carbon capture ratio (CCR) of nearly 100%. It was found that, except for the cell voltage, the other operating parameters do not affect significantly the efficiency of the plant. Compared to the benchmark SOFC-based hybrid cycles using conventional CO2 capture technologies, the SOFC-CLC power plant showed an electric efficiency ∼2 percentage points higher, without requiring high temperature heat exchangers and with a simplified process configuration.
Assessing the carbon sequestration potential of basalt using X-ray micro-CT and rock mechanics Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-20 Ben Callow, Ismael Falcon-Suarez, Sharif Ahmed, Juerg Matter
Biotransformation in water and soil of nitrosamines and nitramines potentially generated from amine-based CO2 capture technology Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-20 Odd G. Brakstad, Lisbet Sørensen, Kolbjørn Zahlsen, Kristin Bonaunet, Astrid Hyldbakk, Andy M. Booth
Nitrosamines (NSAs) and nitramines (NAs) are identified as possible degradation products from amine-based post-combustion CO2-capture (PCCC). Selected NSAs and NAs were subjected to aerobic and anaerobic biodegradation studies. In a screening study with 20 μg/L NSAs and NAs at 20 °C, only NSAs and NAs containing hydroxyl groups (alkanol compounds) exhibited aerobic biotransformation >10% after incubation in 28 days. Extending the biodegradation period to 56 days resulted in ≥80% biotransformation of the examined alkanol NSAs and NAs at 20 °C. Biotransformation (20 °C; 56 days) of the NSA NDELA at different concentrations (1–100 μg/L) did not differ significantly, but both water sources and temperatures affected biotransformation of the tested compounds. Anaerobic biotransformation (20 °C; 56 days) occurred rapidly with alkanol NSAs and NAs, but not with alkyl compounds. Interestingly, 1st order rate coefficients and half-lives indicated comparable or even faster anaerobic than aerobic biotransformation at the same temperature. Predictions of biotransformation pathways suggested that the -OH substituent of alkanol NSAs and NAs was more susceptible to degradation than nitroso- and nitro-substituents.
Dynamic modelling, simulation and basic control of CO2 absorption based on high pressure pilot plant for natural gas treatment Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-20 K.M.S. Salvinder, H. Zabiri, F. Isa, S.A. Taqvi, M.A.H. Roslan, Azmi M. Shariff
The continuous exploration of new gas reserves along with the increase in the global power demand necessitates the development of less demanding technologies, especially in terms of energy minimization. However, the development of CO2-rich type of gas resources poses significant challenges in the sour gas treatment industry due to bulk CO2 contaminants and high overflowing pressure at the well- head. For the treatment of CO2 rich natural gas, reliable data at high CO2 partial pressure condition is very crucial and the insight of the transient conditions must be thoroughly studied to design a controlled process that can handle any disturbances that might arise in the future. This paper reports the dynamic modelling and basic regulatory control studies of a high-pressure absorption pilot plant, which is located at Universiti Teknologi PETRONAS (UTP), for CO2 removal using MEA solvent. Steady state simulation has been demonstrated using Aspen Plus utilizing both equilibrium and rate based approaches. Dynamic and control analysis is then carried out in Aspen Dynamic using a modified equilibrium stage model.
Study on the use of an imidazolium-based acetate ionic liquid for CO2 capture from flue gas in absorber/stripper packed columns: Experimental and modeling Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-20 Fazlollah Zareiekordshouli, Asghar Lashanizadehgan, Parviz Darvishi
In the present work, 1-Ethyl-3-methylimidazolium acetate ([Emim][Ac]) ionic liquid (IL) has been considered for experimental and theoretical investigation of post-combustion carbon dioxide (CO2) capture from flue gas. The absorption and stripping of CO2 into [Emim][Ac] IL has been studied in a typical absorber/stripper system that randomly packed with Raschig ring at absorption pressures of 5–8 bar, absorption temperatures of 298.15–338.15 K and stripping conditions of 1.5 bar in temperature range 363.15–398.15 K. A mathematical model was developed for absorption and stripping processes based on mass transfer concepts and Peng–Robinson equation of state (PR EOS). The validity of the model was verified via comparison of the results achieved by the model with data taken from the experiments performed in this work and VLE data given in the literature. The impacts of parameters such as absorption/stripping pressure and temperature on the performance of CO2 capture, the sorbent flow rate and energy demand at selected operating conditions and specified CO2 capture rates were examined. The experimental tests showed that the recovered CO2 from the stripper column was pure. The results demonstrated that the energy requirement for the CO2 capture IL-based process is about 4890 kW or 2.75 GJ/t CO2. It was also found that the degradation rate of ion liquid is 3.78 wt.% of circulated IL. Using the enhancement factor obtained based on experimental results, the pseudo-first order reaction constant of the CO2 + [Emim][Ac] IL system was estimated. By fitting the kinetics data into Arrhenius equation, the activation energy and frequency factor of the reaction rate constant were found to be 10.317 kJ/mol and 1545 s−1, respectively.
General public reactions to carbon capture and storage: Does culture matter? Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-20 Farid Karimi, Arho Toikka
We scrutinise the controversial carbon capture and storage (CCS) technology from a cross-cultural perspective. The reaction of the public to CCS will considerably affect the development of the technology. Previous research has identified general and local mechanisms in how the general public reacts to CCS. Researchers have noticed that differences exist between countries, but the effects of cross-cultural differences have not been explored in detail. We argue that it is crucial to understand how public perceptions of the technology emerge and form in their individual contexts or embedded in large-scale cultural frameworks. Public reaction to CCS is structured in two dimensions—risk perception and benefit perception—and we design a model with individual and national cultural level predictors. We indicate that effects of individual level variables such as familiarity with technology, or sociodemographic variables such as education, are important but their effects are likely mediated and confounded by the cultural setting people operate in. The results show that, in parallel with other factors such as trust, risk perception is affected by cultural dimensions such as uncertainty avoidance and the society’s short-term or long-term orientation. We provide a framework to understand why and how societies challenge the technology.
Analysis for the speciation in CO2 loaded aqueous MEDA and MAPA solution using 13C NMR technology Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-17 Rui Zhang, Xiao Luo, Qi Yang, Hai Yu, Graeme Puxty, Zhiwu Liang
The competitive and cooperative reactions between the intramolecular primary and secondary amino groups in CO2 absorption have been investigated in this work. N-Methylethylenediamine (MEDA) and N-methylpropane-1,3-diamine (MAPA) were studied with various CO2 loadings at 25 °C. The 13C NMR technology was employed to obtain accurate 13C peak areas and chemical shifts for determining the concentration of each species in both of the diamine-CO2 H2O systems. The results showed that the relative amounts of the species is primary-carbamate >> secondary-carbamate > di-carbamate in the CO2 absorption process. Moreover, the relative hydrolysis order of the carbamates is di-carbamate > secondary-carbamate > primary-carbamate. The competitive and cooperative reaction mechanism was then proposed based on these results. Finally, it was found that in both the MEDA and the MAPA ternary systems, the whole CO2 absorption process can be divided into three stages: competitive stage, buffer stage and hydrolysis stage, each of which showed a different trend in the amount of each species as well as in the pH value.
Impacts of SO2 gas impurity within a CO2 stream on reservoir rock of a CCS pilot site: Experimental and modelling approach Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Maryeh Hedayati, Andrew Wigston, Jan Lennard Wolf, Dorothee Rebscher, Auli Niemi
In order to evaluate chemical impacts of SO2 impurity on reservoir rock during CO2 capture and storage in deep saline aquifers, several batch reactor experiments were performed on laboratory scale using core rock samples from the pilot CO2 injection site in Heletz. In this experiment, the samples were exposed to pure N2(g), pure CO2(g), and CO2(g) with an impurity of 1.5% SO2(g) under reservoir conditions for pressure and temperature (14.5 MPa, 60 °C). Based on the set-up and the obtained experimental results, a batch chemical model was established using the numerical simulation program TOUGHREACT V3.0-OMP. Comparing laboratory and simulation data provides a better understanding of the rock-brine-gas interactions. In addition, it offers an evaluation of the capability of the model to predict chemical interactions in the target injection reservoir during exposure to pure and impure CO2. The best match between the geochemical model and experimental data was achieved when the reactive surface area of minerals in the model was adjusted in order to calibrate the kinetic rates of minerals. The simulations indicated that SO2(g) tends to dissolve rather quickly and oxidizes under a kinetic control. Hence, it has a stronger effect on the acidity of the brine than pure CO2(g) and as a result, increased mineral dissolution and caused the precipitation of sulfate and sulfide minerals. Ankerite, dolomite, and siderite, the most abundant carbonates in the sandstone rock sample, are subject to stronger dissolution in the presence of SO2 gas. The performed simulations confirmed a slower dissolution rate for ankerite and siderite than for dolomite. The model reproduced the precipitation of pyrite and anhydrite as observed in the laboratory. The dissolution of dolomite observed in the batch reaction test with pure N2 is assumed to be due to slight contamination with oxygen and modelling supported this. The inclusion of SO2 increased the porosity over that of the pure CO2 case, and is thus considered to increase the permeability and injectivity of the reservoir as well. Exposure to SO2 also increased the concentration of trace elements. The calibrated kinetic parameters determined in this study will be used to model the injection and long-term behavior of CO2 at the Heletz field site, and may be used for similar geologic reservoirs.
Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Ebuwa Osagie, Chechet Biliyok, Giuseppina Di Lorenzo, Dawid P. Hanak, Vasilije Manovic
It is widely accepted that emissions of CO2, which is a major greenhouse gas, are the primary cause of climate change. This has led to the development of carbon capture and storage (CCS) technologies in which CO2 is captured from large-scale point sources such as power plants. However, retrofits of carbon capture plants result in high efficiency penalties, which have been reported to fall in the range of 7–12% points in the case of post-combustion capture from natural gas-fired power plants. Therefore, a reduction of these efficiency losses is a high priority in order to deploy CCS at a large scale. At the moment, chemical solvent scrubbing using amines, such as monoethanolamine (MEA), is considered as the most mature option for CO2 capture from fossil fuel-fired power plants. However, due to high heat requirements for solvent regeneration, and thus high associated efficiency penalties, the use of alternative solvents has been considered to reduce the energy demand. In this study, a techno-economic assessment of the post-combustion CO2 capture process using 2-amino-2-methyl-1-propanol (AMP) for decarbonisation of a natural gas combined cycle (NGCC) power plant was performed. The thermodynamic assessment revealed that the AMP-based process resulted in 25.6% lower reboiler duty compared to that of the MEA-based process. This was primarily because the AMP solvent can be regenerated at a higher temperature (140 °C) and pressure (3.5 bar) compared to that of MEA (120 °C and 1.8 bar). Furthermore, the efficiency penalty due to the retrofit of the AMP-based process with the natural gas combined cycle power plant was estimated to be 7.1% points, compared to 9.1% points in the case of integration with the MEA-based process. Regardless of the superior thermodynamic performance, the economic performance of the AMP-based process was shown to be better than that of the MEA-based process only for make-up rates below 0.03%. Therefore, use of AMP as a solvent in chemical solvent scrubbing may not be the most feasible option from the economic standpoint, even though it can significantly reduce the efficiency penalty associated with CO2 capture from NGCCs.
Carbon dioxide flow and interactions in a high rank coal: Permeability evolution and reversibility of reactive processes Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Mojgan Hadi Mosleh, Matthew Turner, Majid Sedighi, Philip J. Vardon
Uncertainties exist on the efficiency of CO2 injection and storage in deep unminable coal seems due to potential reduction in the permeability of coal that is induced by CO2 adsorption into the coal matrix. In addition, there is a limited knowledge about the stability of CO2 stored in coal due to changes in gas partial pressure caused by potential leakage. This paper presents an experimental study on permeability evolution in a high rank coal from South Wales coalfield due to interaction with different types of gases. The reversibility of the processes and stability of the stored CO2 in coal are investigated via a series of core flooding experiments in a bespoke triaxial flooding setup. A comprehensive and new set of high-resolution data on the permeability evolution of anthracite coal is presented. The results show a considerable reduction of permeability above 1.5 MPa CO2 pressure that is correlated with the coal matrix swelling induced by CO2 adsorption. Notably studied in this work, the chemically-induced strain due to gas sorption into coal, that has been isolated and quantified from the mechanically-induced strain as a result of changes in effective stress conditions. The results of post-CO2 core flooding tests using helium (He), nitrogen (N2) and methane (CH4) demonstrated a degree of restoration of the initial permeability. The injection of N2 showed no significant changes in the coal permeability and reversibility of matrix swelling. The initial permeability of the coal sample was partially restored after replacing N2 by CH4. Observation of permeability evolution indicates that the stored CO2 has remained stable in coal under the conditions of the experiments.
A long-term strategic plan of offshore CO2 transport and storage in northern South China Sea for a low-carbon development in Guangdong province, China Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Di Zhou, Pengchun Li, Xi Liang, Muxin Liu, Li Wang
Strategic regional planning is an important step towards a successful CCUS development. This paper is the first effort of proposing a development plan of offshore CO2 storage and transport for Guangdong in 2030 and 2050. We attempt to make an ambitious and achievable plan. The cluster-hub model of sources and sinks is adopted, and reuse of existing infrastructures is preferred. The targets of CCUS in Guangdong by 2050 are approximately 8% of the CCS targets that proposed for entire China (ADB, 2015), except a smaller target of 2050. The dual-phase and dual-track approach of ADB’s roadmap is followed. The CCUS phase I before 2030 is characterized by the capture of high-purity CO2 from petrochemical industry and the storage of CO2 mainly related to CO2-EOR. The target of ∼3 Mtpa CCUS in 2030 will be achieved by source-sink match A1. The phase II from 2030 to 2050 is characterized by a wider deployment of CCUS. The target of CCUS in Guangdong is ∼35 Mtpa in 2040 and ∼110 Mtpa in 2050, leading to the cumulative CO2 avoidance of ∼187 MtCO2 for 2031–2040 and ∼730 MtCO2 for 2041–2050. Four source-sink matches are proposed for this phase, including the storage clusters in the Pearl River Mouth Basin and in the Beibuwan Basin in the northern South China Sea. Research with sufficient lead time to support the phased CCUS development is proposed, including databases, feasibility studies, technique R&D, cost estimation, and optimized system design. We are fully aware of the large uncertainty in the years ahead, and regard this planning as a highly general and hypothetic proposal.
Reliable prediction of aqueous dew points in CO2 pipelines and new approaches for control during shut-in Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Darren Rowland, John A. Boxall, Thomas J. Hughes, Saif Z.S. Al Ghafri, Fuyu Jiao, Xiong Xiao, Vijay Pradhan, Eric F. May
Accurate predictions and precise control of the allowable water content in CO2-rich fluids are required in large-scale pipeline operations. Especially during transient shut-in and re-start operations, the pressure decrease associated with cooling may cause the CO2-rich mixture to pass through its dew point, producing an aqueous liquid phase. The pH of this liquid aqueous phase will rapidly decrease as carbonic acid is formed, greatly accelerating the corrosion rate of the carbon steel pipeline. The phase behaviour of CO2-rich fluid mixtures is qualitatively different to that of hydrocarbons, and standard oil and gas property packages in process simulation software may be inadequate for predicting dew points and other key properties. An extensive literature survey reveals 34 data sets where water contents of CO2-rich fluids have been measured near conditions relevant to CO2 pipelines. Following consistency tests, 23 data sets were found to be of good quality and 11 data sets were found to be of poor quality. The good-quality data were compared with predictions from 6 equations of state. Overall, Multiflash’s RKS (Advanced) model was found to provide the best agreement with the aqueous dew point data of CO2-rich fluid phases. A case study is presented wherein it is demonstrated that the formation of a corrosive aqueous phase can be avoided during shut-in via introduction of a relatively small volume of ethanol.
Nonlinear model predictive control and H∞ robust control for a post-combustion CO2 capture process Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Qiang Zhang, Richard Turton, Debangsu Bhattacharyya
This work focuses on the design of a nonlinear model predictive controller (NMPC) and an H∞ robust controller for an MEA-based CO2 capture process. The model used in the NMPC is a nonlinear, additive, autoregressive model with exogenous (NAARX) inputs. Uncertainties are unavoidable in chemical processes. Therefore, a robust controller is designed for the CO2 capture process based on μ-synthesis with a DK-iteration algorithm. The effects of uncertainties due to measurement noise and model mismatches are evaluated for both the NMPC and robust controller. The system disturbances include a number of input and output disturbances such as the flue gas flowrate and composition and variable capture targets. This study shows that the tradeoff between the fast tracking performance of the NMPC and the superior robust performance of the robust controller must be considered while designing the control system for the CO2 capture units.
Modeling the dynamics of remobilized CO2 within the geologic subsurface Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Erik J. Huber, Abraham D. Stroock, Donald L. Koch
Long after CO2 is injected into a brine aquifer, most reservoir-scale fluid dynamic simulations predict large fractions of the original plume will become immobilized via capillary trapping and dispersed throughout the formation. We begin our analysis with a reservoir in this state and consider the effects caused by a depressurization of the domain (e.g. from a nearby production well or newly formed fracture between neighboring reservoirs) and predict the fraction of CO2 that will be remobilized as a result. We then model the dynamics of this remobilized CO2 in two distinct steps: (1) vertical rise within the reservoir, followed by (2) spreading of mobile CO2 into the far-field of the domain and justify this approach from a scaling analysis of the governing equations. We show that a model of relative permeability that takes account of insights from percolation theory near the minimum CO2 saturation leads to much more rapid rise and subsequent radial spreading of remobilized CO2 than a traditional empirical correlation such as the Brooks-Corey model. Furthermore, we find that over a broad range of remobilized CO2 mass fraction and Bond number, the radial extent of the mobile plume does not exceed a factor of 1.8 times the radius of the original immobilized CO2 region.
Processing and characterization of Fe-based oxygen carriers for chemical looping for hydrogen production Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Yoran De Vos, Marijke Jacobs, Isabel Van Driessche, Pascal Van Der Voort, Frans Snijkers, An Verberckmoes
Chemical looping combustion of high sodium lignite in the fluidized bed: Combustion performance and sodium transfer Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Tao Song, Ernst-Ulrich Hartge, Stefan Heinrich, Laihong Shen, Joachim Werther
The Zhundong coalfield in Xinjiang, China, is the largest integrated coal basin newly found. The present work concentrates on the application of chemical looping combustion (CLC) with a Zhundong lignite, which is characterized by high sodium content. Some experiments in a laboratory scale fluidized bed facility with an active iron ore oxygen carrier, were performed using the lignite as fuel and CO2 as gasifying agent at a temperature of 900 °C, with the objective of investigating its combustion performance and sodium transfer behavior in CLC. Results indicate that the gasification reactivity of the three coals follows the order of German lignite > Zhundong lignite > American bituminous coal in the current experimental conditions. During reducing stage, the unique product of sodium transfer from coal to the fly ash is albite (NaAlSi3O8) due to the reactions between sodium and other coal ash. The sodium deposition on the oxygen carrier particles was not found. 40 reducing-oxidizing cycles were performed, and sodium accumulation in the bed materials with cycles was found due to some ash staying in the bed. However, the growth of bed particles due to the sodium accumulation was not observed by determining the particle size distributions of bed materials. This indicates that burning the high sodium Zhundong coal in the present conditions have no influence on the particle agglomeration. Finally, a literature survey was made and results indicate that the main sodium in the Xinjiang coal basin of China is water soluble with an average value of 64%. The pure salt of NaCl, as one common water soluble sodium phase in Zhundong coals, was introduced to a bed of iron ore particles at 900 °C with regard to investigate the influence of NaCl on fluidization stability. Based on the measurements of pressure drop, bed temperature and SEM-EDS, it was found that NaCl does not react with the iron ore but in fact only acts as glue between iron ore particles. Further, the sodium transfer routes in CLC of Zhundong coal with iron ore based oxygen carrier are given and some discussions are made with regard to practical operation. The corrosion problems on the heating surface in the air reactor can be significantly reduced compared to a conventional Zhundong coal fueled furnace, since most of sodium will release and be converted in the fuel reactor.
Chemical looping combustion of four different solid fuels using a manganese-silicon-titanium oxygen carrier Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Matthias Schmitz, Carl Johan Linderholm, Anders Lyngfelt
In chemical looping combustion, solid metal oxide particles are utilized to transport oxygen from the air reactor to the fuel reactor. As fuel and air are never mixed, the energy penalty typically associated with gas separation in first-generation carbon capture and storage technologies can be avoided. To be considered as oxygen carrier for this process, a material should be reactive at relevant conditions, environmentally friendly, non-toxic, mechanically durable and have potential to be produced at low cost in large scale. Combined oxides of manganese and silicon have previously shown promise to meet these requirements. In this study, a spray-dried oxygen carrier based on a combined oxide of manganese, silicon and titanium was examined with respect to its performance in continuous chemical looping combustion of solid fuels. The experiments were carried out in a 10 kW chemical looping pilot unit which uses interconnected fluidized beds for oxygen carrier cycling. Prior to these experiments, the attrition rate was determined in a jet-cup rig. As the particles were comparably small and light, elutriation from the air reactor was high. The fuels used during a total experimental duration of 32 h were wood char, devolatilized hard coal, pet coke and lignite. In addition to varying fuels, the influence of fuel power, solids circulation and fuel reactor temperature were investigated. Gas conversion performance correlated clearly with the volatile content of the fuels, peaking at 97.8% for wood char and 94.6% for pet coke, which is the highest value ever reached for this particular fuel in this unit. Higher temperatures and solids circulation rates increased gas conversion. No decrease in performance over time, in particular no loss of reactivity due to sulphur accumulation, could be detected. The oxygen carrier released gaseous oxygen at relevant conditions. The particles were easily fluidized and fines production was low, suggesting a sufficient lifetime for the purpose.
Synthesis and upscaling of perovskite Mn-based oxygen carrier by industrial spray drying route Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Marijke Jacobs, Tjalling van der Kolk, Knuth Albertsen, Tobias Mattisson, Anders Lyngfelt, Frans Snijkers
Chemical looping combustion (CLC) has inherent separation of the greenhouse gas CO2 by avoiding direct contact between air and fuel. The transfer of oxygen is realised by metal oxide particles that continuously circulate between the air and fuel reactors. Promising particles are perovskite Mn-based oxygen carrier materials, which have proven their performance at lab-scale. To test these particles at an industrial scale, it is necessary to use more raw materials that are widely and cheaply available in bulk quantities. The development of these Mn-based oxygen carriers by the spray drying method was investigated in this study. Furthermore, the production method is transferred to industrial scale so that several tonnes of oxygen carriers could be produced. The characterization and the performance of these particles at lab and industrial scale is discussed. Different Mn ores and oxides were selected to study the effect of the used Mn source on the oxygen carrier performance. Particles suitable for chemical looping were made based on diverse Mn sources with different Mn oxidation states. The performance of the oxygen carrier was found to be heavily impacted by impurities in the raw materials. The best performing Mn oxide was selected for up-scaling and each step of the spray drying process was optimized at large scale. The thermal treatment of the particles at tonne scale remains a challenge, but particles with a good mechanical strength, sphericity and sufficient reactivity for methane were manufactured.
Experimental study of the aqueous CO2-NH3 rate of reaction for temperatures from 15 °C to 35 °C, NH3 concentrations from 5% to 15% and CO2 loadings from 0.2 to 0.6 Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-02-04 Stefano Lillia, Davide Bonalumi, Philip L. Fosbøl, Kaj Thomsen, Gianluca Valenti
The absorption reaction between aqueous NH3 and CO2 was studied using the Wetted Wall Column. A total of 27 different cases are investigated in the region defined by temperatures from 15 °C to 35 °C, NH3 concentrations from 5% to 15%, which are the typical solvent conditions in absorption columns, and lastly CO2 loadings from 0.2 to 0.6. The resulting overall mass transfer coefficient of absorption measured follows the trends described by the modelling of the reactor and the equations used to describe the rate of the absorption reactions. Moreover, the overall mass transfer coefficient of absorption is in agreement with data available in the literature, valid in smaller portions of the investigated region. From the data analysis, the kinetics of the absorption reactions in the liquid phase is characterized. The equation proposed to fit the data is a power law equation which reproduces the experimental results measured at different CO2 loadings. This represents a novelty because in literature the kinetic model of the reaction is usually fitted only to data for unloaded solutions (CO2 loading equal to zero). Hence, in this case there is an experimental evidence that the kinetic model holds true in every loading conditions. The kinetic model intercept the values found in literature in every range of concentration. Consequently, the model is valid in every conditions and the rate of the reaction between NH3 and CO2 in liquid phase is described with an Arrhenius constant with a pre-exponential factor of 1.41·108 [mol/(m3s)] and an activation energy of 60,680 [J/mol], a linear dependence on the CO2 concentration and a dependence on the NH3 with an exponent γ = 1.89. The proposed equation is found to be appropriate for implementation into process simulation software.
The cost of getting CCS wrong: Uncertainty, infrastructure design, and stranded CO2 Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-01-11 Richard S. Middleton, Sean Yaw
Carbon capture, and storage (CCS) infrastructure will require industry—such as fossil-fuel power, ethanol production, and oil and gas extraction—to make massive investment in infrastructure. The cost of getting these investments wrong will be substantial and will impact the success of CCS technology. Multiple factors can and will impact the success of commercial-scale CCS, including significant uncertainties regarding capture, transport, and injection-storage decisions. Uncertainties throughout the CCS supply chain include policy, technology, engineering performance, economics, and market forces. In particular, large uncertainties exist for the injection and storage of CO2. Even taking into account upfront investment in site characterization, the final performance of the storage phase is largely unknown until commercial-scale injection has started. We explore and quantify the impact of getting CCS infrastructure decisions wrong based on uncertain injection rates and uncertain CO2 storage capacities using a case study managing CO2 emissions from the Canadian oil sands industry in Alberta. We use SimCCS, a widely used CCS infrastructure design framework, to develop multiple CCS infrastructure scenarios. Each scenario consists of a CCS infrastructure network that connects CO2 sources (oil sands extraction and processing) with CO2 storage reservoirs (acid gas storage reservoirs) using a dedicated CO2 pipeline network. Each scenario is analyzed under a range of uncertain storage estimates and infrastructure performance is assessed and quantified in terms of cost to build additional infrastructure to store all CO2. We also include the role of stranded CO2, CO2 that a source was expecting to but cannot capture due substandard performance in the transport and storage infrastructure. Results show that the cost of getting the original infrastructure design wrong are significant and that comprehensive planning will be required to ensure that CCS becomes a successful climate mitigation technology. In particular, we show that the concept of stranded CO2 can transform a seemingly high-performing infrastructure design into the worst case scenario.
Sleipner: The ongoing challenge to determine the thickness of a thin CO2 layer Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-01-09 James C. White, Gareth Williams, Andy Chadwick, Anne-Kari Furre, Anders Kiær
Sleipner is the world’s longest-running CO2 storage project. Since injection commenced in 1996 almost 1 million tonnes per year have been injected with more than 16 million tonnes successfully stored by 2016. A comprehensive programme of time-lapse 3D seismic monitoring has been carried out, providing unrivalled imaging of the CO2 plume as it has developed and migrated in the storage reservoir. The plume has a tiered structure comprising a number of thin layers of CO2 of the order of a few metres thick. Determination of accurate layer morphology is key to understanding details of fluid flow processes in the plume which is necessary to demonstrate future storage security. Migration of the topmost layer of CO2, trapped directly beneath the reservoir topseal, determines the longer-term storage performance at Sleipner and here we focus on mapping its travel-time (temporal) thickness. Our primary approach is to use spectral analysis to determine tuning frequencies across the layer and from these to derive temporal thickness. These range from zero at the layer edges to around 16 ms in the central parts of the layer and correlate closely with the base topseal topography. Uniquely, results are then compared with those from other published approaches including amplitude analysis, temporal shifts and direct measurement of temporal spacing on the latest high-resolution seismic data. It is clear that the spectral methods provide robust determination of temporal thickness well below the tuning thickness, and, taken in suitable combination with the various other methods, can provide reliable determination of temporal thickness across the range from close to zero to well above the tuning thickness where explicit layer resolution is obtained. Application of an appropriate layer velocity allows true layer thicknesses to be determined and layer volumetrics to be estimated.
Assessment of two-phase flow on the chemical alteration and sealing of leakage pathways in cemented wellbores Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-01-08 Jaisree Iyer, Stuart D.C. Walsh, Yue Hao, Susan A. Carroll
CO2 capture efficiency and heat duty of solid acid catalyst-aided CO2 desorption using blends of primary-tertiary amines Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-01-02 Wayuta Srisang, Fatemeh Pouryousefi, Priscilla Anima Osei, Benjamin Decardi-Nelson, Ananda Akachuku, Paitoon Tontiwachwuthikul, Raphael Idem
This study evaluated improvements in the CO2 capture process in terms of cyclic capacity, absorption efficiency and heat duty caused by using a primary amine (5 M MEA) blended with a tertiary amine (2 M MDEA or 1.25 M DEAB) and a catalyst-aided desorber loaded with two different solid acid catalysts (γ-Al2O3 or HZSM-5) in a bench scale full cycle CO2 capture plant. The absorber and desorber were stainless steel pipes with inside diameter of 0.05 m and height of 1.50 m. The desorber was loaded with varying amounts of solid acid catalyst at an average bed temperature of 85 °C. The two mixed amine solvents tested, were compared with 5 M MEA each with a circulation rate of 0.06 L/min. Simulated flue gas, 15% CO2 in N2, was used at a total flow rate of 15 SLPM. The results showed that in 5 M MEA system, cyclic capacity and absorption efficiency increased while heat duty decreased when the catalyst amount was increased. In the case of mixed primary and tertiary amines, catalysts contribute to slight improvements. The increase in absorption efficiency was found to be in the order of 5 M MEA: γ-Al2O3 < 5 M MEA: HZSM–5 < 5 M MEA: 2 M MDEA: γ-Al2O3 < 5 M MEA: 2 M MDEA: HZSM–5 < 5 M MEA: 1.25 M DEAB: γ-Al2O3 < 5 M MEA: 1.25 M DEAB: HZSM-5. The relative reduction in heat duty of the system was found to be in the order of 5 M MEA: 1.25 M DEAB: HZSM–5 < 5 M MEA: 2 M MDEA: HZSM–5 < 5 M MEA: 1.25 M DEAB: γ-Al2O3 < 5 M MEA: 2 M MDEA: γ-Al2O3 < 5 M MEA: HZSM-5 < 5 M MEA: γ-Al2O3.
Experimental investigation of CO2 removal from N2 by metal oxide nanofluids in a hollow fiber membrane contactor Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2018-01-02 Hamed Mohammaddoost, Ahmad Azari, Meisam Ansarpour, Shahriar Osfouri
The elimination of carbon dioxide (CO2) using water-based nanofluids (NFs) in a hollow fiber membrane contactor (HFMC) using polypropylene (PP) membrane was experimented. Gas flows in the shell, while NF flows in the fibers. Metal oxide nanoparticles (NPs) such as aluminum oxide (Al2O3), titanium dioxide (TiO2) and silica (SiO2) in the concentrations of 0.05, 0.1 and 0.2 wt % were used in the experiments. Some factors such as gas flow rates, NPs type, NF temperature, NP concentration, as well as the effect of particle size on the separation were investigated. The results clearly show that the highest flux of CO2 occurred for 0.2 wt % concentration of Al2O3 NFs. Mass transfer flux enhancement (MTFE) was defined as the relative mass transfer flux (MTF) of CO2 in the NFs with respect to the MTF of CO2 in the de-ionized water as the base fluid. MTFE changed from 1.29 to 2.25 for the Al2O3 NFs. Among all the results, the best result was obtained for Al2O3 (40 nm) at 1.6 Lit/min liquid flow rate, 25 °C liquid temperature, 5 Lit/min gas flow rate and 40% inlet CO2 concentration which is 98.9% CO2 removal. Finally, a new correlation was developed for the Sherwood (Sh) number for the CO2 mass transfer in the NFs flowing in the fibers. Sh number was developed based on the NFs Reynolds (Re) number, NPs Reynolds (Renp) number, Schmidt (Sc) number, and NPs volume fraction with an average relative error percent (REP) of 1.6% and R2 of 0.99.
Quantifying the effects of depositional environment on deep saline formation co2 storage efficiency and rate Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : Nicholas W. Bosshart, Nicholas A. Azzolina, Scott C. Ayash, Wesley D. Peck, Charles D. Gorecki, Jun Ge, Tao Jiang, Neil W. Dotzenrod
In an effort to reduce carbon dioxide (CO2) emissions from large stationary sources, carbon capture and storage (CCS) is being investigated as one approach in a portfolio of greenhouse gas (GHG) reduction strategies. This work assesses CO2 storage rates and efficiency of saline formations classified by interpreted depositional environment at the regional scale over a 100-year time frame. The focus of this study was placed on developing results applicable to future commercial-scale CO2 storage operations in which an array of injection wells would be used to optimize storage in saline formations. The results of this work suggest future investigations of prospective storage resource in closed or semiclosed formations that may focus less heavily on interpretation of depositional processes. However, the results illustrate the relative importance of depositional environment, aquifer depth, structural geometry, and boundary conditions on the rate of CO2 storage in closed or semiclosed systems.
Comparison of various configurations of the absorption-regeneration process using different solvents for the post-combustion CO2 capture applied to cement plant flue gases Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-27 Lionel Dubois, Diane Thomas
Carbon Capture Utilization or Storage (CCUS) has gained widespread attention as an option for reducing CO2 emissions from power plants but specific developments are still needed for the application to cement plants. More precisely, the post-combustion CO2 capture process by absorption-regeneration is the more mature technology but its cost reduction is still necessary. The present study is focusing on Aspen Hysys™ simulations of different CO2 capture process configurations (namely “Rich Solvent Recycle” (RSR), “Solvent Split Flow” (SSF), “Lean/Rich Vapor Compression” (L/RVC)) applied to the flue gas coming from the Norcem Brevik cement plant (taken as case study) and using three different solvents, namely: monoethanolamine (MEA), piperazine (PZ) and piperazine-methyldiethanolamine (MDEA) blend. For each configuration and solvent, different parametric studies were carried out in order to identify the operating conditions ((L/G)vol., split fraction, flash pressure variation, etc.) minimizing the solvent regeneration energy. Total equivalent thermodynamic works and utilities costs were also analyzed. It was shown that the configurations studied allow regeneration energy savings in the range 4–18%, LVC and RVC leading to the higher ones. As perspectives, other configurations and combination of configurations will be considered in order to further reduce the energy consumption of the process.
Influence of formaldehyde on N-nitrosopiperazine formation from nitrite and piperazine in CO2 capture Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-27 Yan Zhou, Yiheng Rao, Tielin Wang, Klaus-J. Jens
Piperazine (PZ) based amine blends are promising solvents for post-combustion CO2 capture, but PZ can form potential carcinogenic nitrosamines from nitrite. In this work, the kinetics of the reaction between nitrite and PZ to form N-nitrosopiperazine (MNPZ) was determined in 0.1–0.5 mol L−1 PZ in the presence of 17–170 mmol L−1 formaldehyde at 60–135 °C. The nitrosation of PZ can be catalyzed by formaldehyde, a primary degradation product of PZ. And the reaction involving nitrite and PZ is first order in nitrite, formaldehyde, and hydronium ion. A kinetic model was established, and the activation energy is 33.6 ± 1.8 kJ mol−1 with a rate constant of 2.3 × 103 ± 0.4 × 103 L2 mol−2 s−1 at 100 °C. The kinetics will be helpful to develop strategies to reduce nitrosamine formation and accumulation in PZ based CO2 capture systems.
Quantifying CO2 storage efficiency factors in hydrocarbon reservoirs: A detailed look at CO2 enhanced oil recovery Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-29 Wesley D. Peck, Nicholas A. Azzolina, Jun Ge, Nicholas W. Bosshart, Matthew E. Burton-Kelly, Charles D. Gorecki, Andrew J. Gorz, Scott C. Ayash, David V. Nakles, L. Stephen Melzer
Carbon dioxide (CO2) enhanced oil recovery (EOR) will likely be the primary means of geologic CO2 storage during the early stages of commercial-scale carbon capture and storage (CCS) because of the inherent economic incentives as well as the abundant experience and demonstrated success in the United States, where CO2 EOR has been employed since 1974. The work presented here estimates CO2 storage efficiency factors in CO2 EOR operations using a unique industry database of CO2 EOR sites and 12 different reservoir simulation models. The simulation models encompass fluvial clastic and shallow shelf carbonate depositional environments for reservoir depths of 1219 and 2438 m (4000 and 8000 feet) and 7.6-, 20-, and 64-m (25-, 66-, and 209-foot)-thick pay zones. A novel statistical modeling technique incorporating the Michaelis–Menten function is used to generate empirical percentile estimates of CO2 storage efficiency factors. West Texas San Andres dolomite water alternating gas (WAG) CO2 flood performance data were used to derive P10, P50, and P90 CO2 storage efficiency factors of 0.76, 1.28, and 1.74 Mscf/STB (stock tank barrel) of original oil in place. Median CO2 storage efficiency factors from continuous CO2 injection following conventional waterflood varied from 15% to 61% and 8% to 40% for fluvial clastic and shallow shelf carbonate simulation models, respectively, while those from WAG injection varied from 14% to 42% and 8% to 31%, respectively. Variation in the CO2 storage efficiency factors was largely attributable to reservoir depth (a surrogate for reservoir pressure and temperature) and lithology (clastic versus carbonate). The results of this work provide practical information that can be used to quantify CO2 storage resource estimates in oil reservoirs during CO2 EOR operations (as opposed to storage following depletion) and the uncertainty associated with those estimates.
Corrigendum to “The latest monitoring progress for Shenhua CO2 storage project in China” [International Journal of Greenhouse Gas Control, 60 (2017) 199–206] Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-27 Zhao Xinglei, Ma Rui, Zhang Feng, Zhong Zhencheng, Wang Baodeng, Wang Yongsheng, Li Yonglong, Weng Li
Chemical looping with air separation (CLAS) in a moving bed reactor with CuO/ZrO2 oxygen carriers Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-21 Young Ku, Hsuan-Chih Wu, Chia-Wei Chang, Shr-Han Shiu
Zirconia supported CuO oxygen carriers were prepared for carrying out chemical looping with oxygen uncoupling (CLOU) and chemical looping with air separation (CLAS) operation in a thermogravimetric analyzer (TGA), a fixed bed reactor and a moving bed reactor (MBR). In this study, graphite used as solid fuel for CLOU with CuO/ZrO2 oxygen carriers was also explored in a fixed bed reactor. 40 wt.% CuO/ZrO2 particles sintered at 1000 °C revealed reasonable reactivity without noticeable agglomeration as observed. For fixed bed operation, time required for graphite combustion with CuO/ZrO2 was decreased for experiments conducted at higher reaction temperatures. For experiments carried out in the moving bed reactor, the oxygen concentration and oxygen molar flow rate in the outlet stream can be adjusted by varying operating temperatures, CuO/ZrO2 flow rate, and carrier gas (N2) flow rate. Therefore, moving bed reactors are technically feasible to serve as fuel reactor for chemical looping with air separation.
Experimental study on the effects of an ionic liquid for CO2 capture using hollow fiber membrane contactors Int. J. Greenh. Gas. Con. (IF 3.741) Pub Date : 2017-12-14 Sadegh Rostami, Peyman Keshavarz, Sona Raeissi
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