Experimental pore-scale analysis of carbon dioxide hydrate in sandstone via X-Ray micro-computed tomography Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-19 Dhifaf Sadeq, Stefan Iglauer, Maxim Lebedev, Taufiq Rahman, Yihuai Zhang, Ahmed Barifcani
Carbon dioxide geo-sequestration (CGS) into sediments in the form of (gas) hydrates is one proposed method for reducing anthropogenic carbon dioxide emissions to the atmosphere and, thus reducing global warming and climate change. However, there is a serious lack of understanding of how such CO2 hydrate forms and exists in sediments. We thus imaged CO2 hydrate distribution in sandstone, and investigated the hydrate morphology and cluster characteristics via x-ray micro-computed tomography in 3D in-situ. A substantial amount of gas hydrate (∼17% saturation) was observed, and the stochastically distributed hydrate clusters followed power-law relations with respect to their size distributions and surface area-volume relationships. The layer-like hydrate configuration is expected to reduce CO2 mobility in the reservoir, and the smaller than expected hydrate surface-area/volume ratio will reduce methane production and CO2 storage capacities. These findings will aid large-scale implementation of industrial CGS projects via the hydrate route.
Field-data analysis and hydromechanical modeling of CO2 storage at In Salah, Algeria Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-18 Tore Ingvald Bjørnarå, Bahman Bohloli, Joonsang Park
The permeability of a reservoir is a key parameter to determine the pressure response due to production and injection and its concomitant geomechanical response. A fractured reservoir affects the fluid flow by increased permeability, which can be further enhanced by elevated pore pressure. The CO2 storage project at Krechba, In Salah, Algeria, was concluded in 2011, but it provided unique and valuable geomechanical data and still remains an important site to study geomechanical processes. It has previously been shown that fracture injection, i.e. injection of CO2 above fracture pressure, is an important transport mechanism. Here we analyze the pressure response from the many temporary shut-ins during injection to justify a proposed correlation between pressure and permeability (power-law expressions) in the reservoir. The correlation is validated using field-data: pressure response in the reservoir and surface heave from InSAR data. Although the shut-in curves from pressure data at In Salah cannot provide the permeability directly, due to its complex injection history (rate and duration), they can show how the permeability varies with pore pressure and provide evidence of the fracture pressure. A recently developed efficient up-scaled numerical model of fully coupled poroelasticity and two-phase flow that effectively captures the main processes in the high-aspect ratio reservoir of In Salah, allows for the current analysis. This model illustrates that a static geomodel cannot explain the observed pressure response and surface heave, and is subsequently used to fit the parameters in the proposed correlation for the pressure-dependent reservoir permeability. Although there are three injection wells at In Salah, KB501, KB502 and KB503, this study is supported primarily by the data from KB501 and KB503. The correlation for the reservoir permeability provides a good match with both the pressure response in the reservoir and the surface heave above the injection wells, thus illustrating that irreversible and non-elastic processes can be approximated with non-linear material properties. For KB502 the geological setting is much more complicated and the response and behavior around the injection well is strongly depending on the behavior of a large and intersecting fracture zone and it still remains crucial to characterize properties of fault/fracture zones, such as thickness, transmissivity, stiffness and porosity.
Hydrotalcites and hydrated Mg-carbonates as carbon sinks in serpentinite mineral wastes from the Woodsreef chrysotile mine, New South Wales, Australia: Controls on carbonate mineralogy and efficiency of CO2 air capture in mine tailings Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-17 Connor C. Turvey, Siobhan A. Wilson, Jessica L. Hamilton, Alastair W. Tait, Jenine McCutcheon, Andreas Beinlich, Stewart J. Fallon, Gregory M. Dipple, Gordon Southam
Carbon mineralisation of ultramafic mine tailings can reduce net emissions of anthropogenic carbon dioxide by reacting Mg-silicate and hydroxide minerals with atmospheric CO2 to produce carbonate minerals. We investigate the controls on carbonate mineral formation at the derelict Woodsreef chrysotile mine (New South Wales, Australia). Quantitative XRD was used to understand how mineralogy changes with depth into the tailings pile, and shows that hydromagnesite [Mg5(CO3)4(OH)2·4H2O], is present in shallow tailings material (<40 cm), while coalingite [Mg10Fe3+2(CO3)(OH)24·2H2O] and pyroaurite [Mg6Fe3+2(CO3)(OH)16·4H2O] are forming deeper in the tailings material. This indicates that there may be two geochemical environments within the upper ∼1 m of the tailings, with hydromagnesite forming within the shallow tailings via carbonation of brucite in CO2-rich conditions, and pyroaurite and coalingite forming under more carbon limited conditions at depth. Radiogenic isotope results indicate hydromagnesite and pyroaurite have a modern (F14C > 0.8) atmospheric CO2 source. Laboratory-based anion exchange experiments, conducted to explore stable C isotope fractionation in pyroaurite, shows that pyroaurite δ13C values change with carbon availability, and 13C-depleted signatures are typical of hydrotalcites in C-limited environments, such as the deep tailings at Woodsreef. Quantitative XRD and elemental C data estimates that Woodsreef absorbs between of 229.0–405.1 g CO2 m−2 y−1.
The effect of nitrogen adsorption on vacuum swing adsorption based post-combustion CO2 capture Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-16 Ashwin Kumar Rajagopalan, Arvind Rajendran
The importance of nitrogen adsorption, an often neglected topic, on post-combustion CO2 capture using vacuum swing adsorption is evaluated. Several hypothetical adsorbents are generated by parametrizing their affinities using the Langmuir adsorption isotherm. By performing detailed process simulation and optimization, it is found that N2 affinity has a strong impact on the ability of the process to concentrate and recover CO2. It is also demonstrated that the energy required to remove N2 can play an important role in determining the total parasitic energy of the process. Lower parasitic energies are obtained for adsorbents that show weak N2 affinity and high CO2/N2 selectivity.
Simulation of post-combustion CO2 capture process by non-equilibrium stage hydrate-based gas separation technology Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-13 Luling Li, Shuanshi Fan, Qiuxiong Chen, Guang Yang, Jinzhou Zhao, Na Wei, Yonggang Wen
To simulate the process of hydrate-based gas separation for post-combustion CO2 capture in non-equilibrium situation, the operational pressure of hydration reaction should be specified firstly, which was depending on the dissociation pressure and the driving force. As the main effect factor of dissociation pressure, the mole fraction of water L/(L+V) in the feed should be predicted in priori. And then the driving force could be sequentially determined based on the systematic analyses. In this work, a new computational method to predict L/(L+V) was proposed. Then based on the thermodynamic model, proposed in our previous work, CPA-SRK + Chen-Guo model, and the three-phase isothermal flash calculation method, we simulated the non-equilibrium stage hydrate-based gas separation technology (for the flue gas containing 17% CO2 and 83% N2 at the condition of 277K) with stage-by-stage calculation. For each stage, the optimized operational pressure of each stage was specified in advance, and then the rate as well as the composition of the main flows were subsequently calculated with flash calculation. Based on the obtained results, it was suggested that four stages of hydration reactions were necessary to obtain a 90% CO2 purity. Furthermore, the performances concerning on split fractions and separation factors were also assessed.
Estimating the pressure-limited CO2 injection and storage capacity of the United States saline formations: Effect of the presence of hydrocarbon reservoirs Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-11 Hossein Jahediesfanjani, Peter D. Warwick, Steven T. Anderson
The U.S. Geological Survey (USGS) national assessment of carbon dioxide (CO2) storage capacity evaluated 192 saline Storage Assessment Units (SAUs) in 33 U.S. onshore sedimentary basins that may be utilized for CO2 storage (see USGS Circular 1386). Similar to many other available models, volumetric analysis was utilized to estimate the initial CO2 injection and storage capacity of these SAUs based on aquifer characteristics and buoyant and residual trapping. The factor being almost always overlooked in most CO2 storage capacity models is that many of the evaluated SAUs contain large numbers of both conventional and unconventional discovered and undiscovered oil and gas reservoirs. The hydrocarbon production and pressure distribution of the resident oil and gas reservoirs may be negatively influenced by the propagated CO2 plume and pressure front resulting from a CO2 injection and storage operation in the surrounding SAU.To have a more realistic and accurate estimation of CO2 injection and storage capacity in saline formations, a model was previously developed that considers the CO2 injectivity of a given formation, underground pressure build-up limitations imposed by the rock fracturing pressure and the presence of hydrocarbon reservoirs within these aquifers. The developed method estimates the pre–brine extraction, pressure-limited CO2 injection and storage capacity of a saline formation by applying 3D numerical simulation only on the effective injection area (Aeff) surrounding each CO2 injection well utilizing TOUGH2-ECO2N simulation software.
CO2 and H2S absorption by MEA solution in packed-bed columns under inclined and heaving motion conditions - Hydrodynamics and reactions performance for marine applications Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-10 Ion Iliuta, Faïçal Larachi
Two-phase countercurrent flow dynamics and simultaneous CO2 and H2S removal performance were studied in countercurrent randomly packed-bed columns with fourth generation Raschig super-Rings exposed to static inclination and heaving motion via an unsteady-state comprehensive three-dimensional model. Gas-liquid countercurrent flow displays a gradual deviation to axial symmetry with the increase of angle of the packed-bed column inclination. CO2 absorption process is negatively impacted in inclined packed-bed columns and the deficit in CO2 removal performance increases with the increase of H2S concentration in gas phase. H2S removal efficiency is marginally reduced and mostly at considerable packed bed inclinations. Under heaving motion of the packed-bed column, an oscillatory two-phase flow and CO2-monoethanolamine (MEA) absorption process performance develop around the steady-state solution of the column stationary state prior to heaving application. As externally-generated packed-bed column oscillations, the heaving motion impacts more CO2 absorption because of very high rate constant of the reaction between H2S and MEA and because the packed-bed column is exposed only to small episodes of time to maximum/minimum heaving acceleration where H2S removal efficiency can be affected.
China baseline coal-fired power plant with post-combustion CO2 capture: 2. Techno-economics Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-01 Surinder Singh, Haoren Lu, Qian Cui, Chufu Li, Xinglei Zhao, Wenqiang Xu, Anthony Y. Ku
Global efforts to advance CO2 capture technologies have produced a strong base of field experience and modeling capability to inform efforts to deploy this technology. In China, there are some important features of power plant construction, operation, and financing that lead to lower costs of CO2 capture relative to the United States and the most of the rest of the world. Moreover, unique aspects of the policy landscape in China, such as an openness to partial capture solutions in the near-term, allow for flexibility in deployment strategy. In this study, we define a set of “China baseline” reference cases and use them to analyze the costs of retrofit post-combustion CO2 capture at supercritical coal-fired power plants in China. We find the cost of post-combustion CO2 capture from power plants in China ranges from about 260 to 280 RMB/tCO2 (40–43 USD/tCO2) captured and 390 to 480 RMB/tCO2 (60–74 USD/ tCO2) avoided. This is at the higher end of the range of published literature estimates for China, but significantly lower than the corresponding ranges in the US for nominally the same technological approach. Lower costs in China have been primarily ascribed to lower capital costs, but a clear analysis of the full set of drivers for cost differences has not yet been published. Our analysis confirms the importance of capital savings, identifies the contributions from other significant factors such as fuel costs and power plant utilization, and explores several strategic implications for how these cost drivers might impact the deployment of CCS in China.
Homogeneous and heterogeneous formation of SO3 in flue gases burning high sulfur coal under oxy-fuel combustion conditions Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-01 Haiping Xiao, Yu Ru, Qiyong Cheng, Chaozong Dou, Cong Qi
Numerical study of mixed working fluid in an original oxy-fuel power plant utilizing liquefied natural gas cold energy Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-10-01 Yixiao Han, Lei Cai, Yanlei Xiang, Yanwen Guan, Wenbin Liu, Lu Yu, Ying Liang
Oxy-fuel combustion is considered one of the most promising technologies for carbon capture and storage (CCS) in power plant. The working fluid, which is composed of CO2 and H2O, is obligatory to moderate the combustion temperature in oxy-fuel systems. The content of H2O in the working fluid has a significant influence on system performance. An original oxy-fuel power plant with the utilization of liquefied natural gas (LNG) cold energy is proposed, and the H2O content in the working fluid is adjustable in the work. The results reveal that when the H2O mass fraction is less than 0.3, the system efficiency increases with the increase of the H2O content in the working fluid. When the H2O mass fraction in the working fluid rises over 0.3, the system efficiency decreases with the increase of H2O content due to the decrease of the recycling heat carried by H2O. The optimum heat transfer effect of the recirculating H2O is obtained when the H2O mass fraction is 0.3, and the optimal thermal efficiency is 58.3%. Compared to dry cycle, the thermal efficiency of the proposed system is increased by 17.3% under the optimum condition.
Techno-economic analysis of CO2 capture from a 1.2 million MTPA cement plant using AMP-PZ-MEA blend Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-27 Chikezie Nwaoha, Martin Beaulieu, Paitoon Tontiwachwuthikul, Mark D. Gibson
This research covered the rate-based process simulation (ProMax® 4.0) and techno-economic analysis of carbon dioxide (CO2) capture from a 1.2 million metric tonne per annum cement plant using aqueous 2 kmol/m3 AMP-1 kmol/m3 PZ-2 kmol/m3 MEA blend. The waste gas composition for this study was provided by a cement plant from Quebec, Canada. The effect of amine type, energy penalty, and CO2 capture efficiency (50% to 90%) on the capture costs (US$/tonne CO2 and US$/tonne cement) were investigated. Sensitivity analysis on the impact of CO2 capture plant, carbon tax (US$ 20 to US$ 40 per tonne of CO2), CO2 sales price (US$ 10 to US$ 40 per tonne of CO2), energy penalty and CO2 capture efficiency on the cement price was also investigated. Results revealed that at 90% CO2 capture efficiency, the capture costs of AMP-PZ-MEA (US$77.34/tonne CO2 and US$44.94/tonne cement) is lower than that of MEA (US$93.23/tonne CO2 and US$54.17/tonne cement). Results also revealed that the total equipment cost and capital expenditure (CAPEX) of MEA system (US$ 29.76 million and US$ 147.12 million) higher than that of AMP-PZ-MEA blend (US$ 23.39 million and US$ 127.59 million).Cash flow analysis showed that without adding a CO2 capture unit to a cement plant, carbon tax increased the cement price up to 22.9%. However, a combination of the high carbon tax, high CO2 sales price, low energy penalty, and high capture efficiency increased the cement price up to 1.2% for the MEA system but reduced the cement price up to 5% for the AMP-PZ-MEA system. This comprehensive study shows that a cost-effective and energy-efficient amine blend, energy penalty, CO2 capture efficiency, carbon tax, and CO2 sales prices are all integral towards reducing the cement price while significantly reducing the CO2 emissions.
Effect of CO2 on P- and S-wave velocities at seismic and ultrasonic frequencies Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-24 Nicolaine Agofack, Serhii Lozovyi, Andreas Bauer
Time-lapse seismic is a widely used technology for monitoring the geological sequestration of carbon dioxide (CO2), consisting of mapping its movement in the subsurface and of demonstrating that the CO2 is safely stored in the reservoir (Xue and Ohsumi, 2004). In this work, the effect of CO2 on P- and S-wave velocities was investigated. Laboratory measurements were performed with Castlegate sandstone both at seismic frequencies (1–155 Hz), and at ultrasonic frequency (around 500 kHz). Different CO2 saturations between 2% and 10% were obtained by controlled depressurization of CO2-saturated water with which the sandstone sample had been saturated with. At seismic frequencies, the results of the experiments revealed that P-wave velocity is strongly reduced in the presence of free gas CO2 in the pore space, whereas at ultrasonic frequency, the P-wave velocity changed only slightly. Therefore, the presence of free CO2 gas increased significantly the P-wave dispersion between seismic and ultrasonic frequencies. The S-wave velocity, on the other hand, was hardly affected by the pore fluid at seismic frequencies. At seismic frequencies, P- and S-wave velocities were consistent with the Biot–Gassmann model. The P-wave velocity dispersion and corresponding attenuation were simulated by applying the Cole–Cole model. The transition frequency was found around 200 kHz.
Using mercury injection pressure analyses to estimate sealing capacity of the Tuscaloosa marine shale in Mississippi, USA: Implications for carbon dioxide sequestration Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-24 Celeste D. Lohr, Paul C. Hackley
The role of flow rates on flow patterns and saturation in high-permeability porous media Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-20 Lanlan Jiang, Sijia Wang, Xingbo Li, Jing Liu, Yu Liu, Ziqiu Xue
This study aimed to investigate dynamic CO2 drainage using high-resolution magnetic resonance imaging (MRI) technology. Gaseous and supercritical CO2 were injected downward in brine-saturated porous media at different flow rates at 40 °C/6 MPa and 40 °C/8 MPa. These flow rates (0.015, 0.03 and 0.1 mL/min, under 10 Mt/year), as reflected in, were chosen according to the distance (1 km–100 m) from the injection well. Three stages were found from the change of signal intensity during CO2 drainage: before the CO2 front reached the field of view (FOV), breakthrough, and steady state. Channelling or drainage fronts immediately established through the large pores, and CO2 travelled vertically through these channels until breakthrough. The breakthrough time decreased with increasing flow rates and was longer for ScCO2 than gCO2 at the same flow rate, resulting in a longer residence time for ScCO2 in the sample. At low flow rates, the fingers first established along the larger pore spaces (especially at 0.015 mL/min) and then gradually extended into adjacent regions, resulting in a relatively flat interface. However, at high flow rates, the front moved along the larger pore spaces until breakthrough. The flow patterns for ScCO2 drainage were more uniform than those for gCO2 drainage. The pore volume fraction occupied by CO2, as a quantitative parameter of the flow pattern, reflected that the sweep efficiency and pore space utilization were optimized at 0.03 mL/min (Ca = 4.35 × 10−9 for gCO2 and Ca = 1.06 × 10-8 for ScCO2). The effect of the flow rate on the CO2 saturation and distribution was analysed. At low flow rates, the saturation gradient along the porous media gradually reduced, but trend to be stable at high flow rates. Additionally, the saturation at breakthrough and steady state were observed to be linearly related to the maximum rate of change in saturation during CO2 injection. Overly fast drainage results in relatively low saturation and an inhomogeneous distribution. The results can be applied to provide information for enhancing pore space utilization and improving sweep efficiencies during field storage.
Economic assessment of chemical looping oxygen production and chemical looping combustion in integrated gasification combined cycles Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-20 Schalk Cloete, Andrew Tobiesen, John Morud, Matteo Romano, Paolo Chiesa, Antonio Giuffrida, Yngve Larring
Chemical looping promises significant reductions in the cost of CO2 capture and storage (CCS) by enabling energy conversion with inherent separation of CO2 at almost no energy penalty. This study evaluates the economic performance of a novel power plant configuration based on the principle of packed bed chemical looping. The new configuration, called COMPOSITE, integrates packed bed chemical looping combustion (PBCLC) and chemical looping oxygen production (CLOP) into an integrated gasification combined cycle (IGCC) power plant. The CLOP unit achieves air separation with minimal energy penalty and the PBCLC unit achieves fuel combustion with inherent CO2 capture. The COMPOSITE configuration achieved a competitive CO2 avoidance cost (CAC) of €45.8/ton relative to conventional IGCC with pre-combustion CO2 capture with €58.4/ton. However, the improvement was minimal relative to a simpler configuration using an air separation unit (ASU) instead of the CLOP reactors, returning a CAC of €47.3/ton. The inclusion of hot gas clean-up further improved the CAC of the COMPOSITE configuration to €37.8/ton. Optimistic technology assumptions in the form of lower contingency costs and better CLOP reactor performance reduced the CAC to only €24.9/ton. Further analysis showed that these highly efficient chemical looping plants will be competitive with other low-carbon power plants (nuclear, wind and solar) in a technology-neutral climate policy framework consistent with a 2 °C global temperature rise. Economic attractiveness improves further in a high CO2 tax scenario where large-scale deployment of CO2 negative bio-CCS plants is required.
A compact and easy-to-use mass spectrometer for online monitoring of amines in the flue gas of a post-combustion carbon capture plant Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-20 Liang Zhu, Tomáš Mikoviny, Anne Kolstad Morken, Wen Tan, Armin Wisthaler
We herein report on the adaptation and deployment of a compact and easy-to-use mass spectrometer for online monitoring of amines in industrial flue gas at ppb to ppm levels. The use of ammonia as a source gas in proton-transfer-reaction mass spectrometry (PTR-MS) greatly simplifies the detection of amines, making it possible to use a low-end commercial instrument version (PTR-QMS 300) for the measurements. We characterized the analytical performance of the instrument (sensitivity, limit of detection, precision, matrix effects) for nine solvent amines (monoethanolamine, dimethylaminoethanol, aminomethylpropanol, methyldiethanolamine, diglycolamine, piperazine, aminoethylpiperazine, methylpiperazine, N-(2-hydroxyethyl)piperazine) and three degradation amines (methylamine, dimethylamine, trimethylamine). The new analyzer was tested and validated in side-by-side measurements with established emission monitoring techniques at the Technology Centre Mongstad (TCM) in Norway. After validation, the instrument was permanently installed on top of the absorber tower to deliver real-time amine emission data to the plant information management system.
Effects of supercritical CO2 injection on sandstone wettability and capillary trapping Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-20 L.M. Valle, R. Rodríguez, C. Grima, C. Martínez
Evaluation, development, and validation of a new reduced mechanism for methane oxy-fuel combustion Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-15 Fan Hu, Pengfei Li, Junjun Guo, Kai Wang, Zhaohui Liu, Chuguang Zheng
The chemical kinetics under oxy-fuel combustion is significantly different from that of conventional air-combustion due to the effect of the high CO2 concentration. Although previous studies have made substantial achievement in reaction mechanisms for air-combustion, their performance under oxy-fuel conditions is still unknown. This study proposes a new 22-species, 19-step reduced mechanism for methane oxy-fuel combustion, developed using comprehensive mechanism evaluation, reduction, and validation methods. First, through quantitative error evaluation against a large experimental data set, for the first time we find that USC-Mech II obtains the best overall predictions among seven detailed combustion mechanisms in oxy-fuel conditions, particularly for the prediction of CO concentration. This detailed mechanism is then thoroughly simplified (including both skeletal and time-scale reduction) with error control under both atmospheric and pressurized oxy-fuel conditions. The obtained reduced mechanism is systematically validated using the detailed mechanism and the relative errors are found to be less than 10%. Relative to other mechanisms, this specially developed reduced mechanism for oxy-fuel combustion not only has minimal species, but also significantly improves the prediction of CO formation. The chemical influence of CO2 under oxy-fuel conditions is further discussed to identify dominant elementary reactions for CO formation, which is important for future development of methane oxy-fuel combustion.
All microannuli are not created equal: Role of uncertainty and stochastic properties in well leakage prediction Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-13 Alexandre Lavrov, Malin Torsæter
Carbon Capture and Storage (CCS) as a method for climate mitigation relies on CO2 being locked up in subsurface reservoirs with a long-term perspective. Active and abandoned wellbores are among the major potential leakage paths for CO2, and their success as "gate keepers" relies on the quality of well cement. The length requirements and recommended practices for cement sheaths in active wells vary from country to country. In this study, we investigate how stochastic properties of the microannulus may affect the recommended "safe length " of cement sheath, should assigning such length be attempted for CO2 wells. We demonstrate, by means of a simple numerical model, that variation in the width of the microannulus along the well makes it a challenging task to assign a figure to the "safe cement-sheath length", even though longer cement sheaths do indeed reduce the risk of leakage. Variation in the mean value or standard deviation of the microannulus width by only 10% changes the recommended length of the cement sheath by up to an order of magnitude. This finding sheds new light on the use and added value of more accurate leakage prediction models: due to the uncertainties in and the lack of information about the properties of microannuli, such models should focus on investigating the effects of different operational and in-situ factors on the leakage potential rather than on attempting to accurately predict the leakage flow rate, however tempting such prediction exercise might seem at first glance.
Implementing adaptive scaling and dynamic well-tie for quantitative 4-D seismic evaluation of a reservoir subjected to CO2 enhanced oil recovery and associated storage Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-13 Olarinre Salako, Lu Jin, César Barajas-Olalde, John A. Hamling, Charles D. Gorecki
History-matched simulation modeling can be used to estimate field dynamic reservoir properties and connectivity between wells. However, results are less accurate away from the well locations where the field data are obtained. 4-D seismic data can help improve the accuracy between wells and across the field. This study used data from an oil field undergoing active CO2 injection for enhanced oil recovery and associated CO2 storage. The change in seismic amplitude, changes in inverted P-wave velocity, and impedance in the reservoir layer are in turn correlated with the pore volume scaled changes in the dynamic reservoir properties at well locations. Impedance and velocity changes yielded the most robust correlations. The correlated linear relations at three injectors were used to invert for the pore volume scaled changes in saturations and pressure between wells and across the field. Validation at the producer yielded 69% accuracy. By tying the 4-D seismic with the reservoir properties at the injectors using repeat pulsed-neutron log data and the simulation models, a good level of confidence is established in the inverted pore volume scaled changes in the dynamic reservoir properties in the interwell spaces. The inverted reservoir properties can be used to further history-match the simulation model to improve the interwell prediction of the long-term fate of the associated CO2 storage.
Influence of substitution of water by organic solvents in amine solutions on absorption of CO2 Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-11 Monica Garcia, Hanna K. Knuutila, Ugochukwu Edwin Aronu, Sai Gu
Aqueous amine solutions are the most used solvents for chemical absorption of CO2. Substituting part of the water by organic solvents in aqueous amine solutions aims to take advantage of the lower partial pressure and higher CO2 solubility. In this work, the influence of four organic solvents on solution density, viscosity, N2O solubility and absorption kinetics are studied. The organic solvents, Monoethylene Glycol (MEG), Diethylene Glycol (DEG), Triethylene Glycol (TEG) and CARBITOL, are blended with two amine solutions: MEA and DEEA-MAPA blend. The results show that the addition of organic solvents increases the density and viscosity. Furthermore, the N2O solubility, used to estimate the physical solubility of CO2 into a reactive system, increases when part of the water is substituted with an organic solvent. The kinetic experiments with a double stirred cell showed that in case of aqueous 5 M MEA, the substitution of part of the water increases both the mass transfer and kinetic coefficients of the CO2, whereas the substitution in the 3M DEEA + 2M MAPA solution was not that favorable and only the substitution of MEG showed enhancement on the mass transfer and kinetic coefficients over the whole temperature range studied. The results can be partly explained by the changes in viscosity and N2O solubility in the different systems, since the viscosity of the MEA organic solvent blends is lower compared to that of DEEA + MAPA blends and have less negative influence on the kinetics. At the same time, the increase of N2O solubility in the MEA blends is much higher than in DEEA + MAPA blends, resulting in more CO2 available to react. Finally, the kinetic coefficients results are discussed together with dielectric constant of the dilution media.
Lessons learned and best practices derived from environmental monitoring at a large-scale CO2 injection project Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-07 Kerryanne M. Leroux, Nicholas A. Azzolina, Kyle A. Glazewski, Nicholas S. Kalenze, Barry W. Botnen, Justin T. Kovacevich, Pride T. Abongwa, Jeffrey S. Thompson, Erick J. Zacher, John A. Hamling, Charles D. Gorecki
Near-surface soil gas and groundwater measurements can be helpful tools in assuaging concerns of potential out-of-zone migration of CO2 from a geologic storage unit into the overlying near-surface environment. These data, therefore, help to build confidence with local stakeholders and regulators that stored CO2 is not impacting surface/near-surface environments. Routine monitoring of soil gas concentrations in the vadose zone can be used to show a lack of change or effect. However, both air temperature modeling and the Romanak et al. (2012) process-based approach should be applied when soil gas data are evaluated, as increased CO2 concentrations can occur naturally from changes in the soil environment. Laboratory testing of groundwater and formation rock (drill cuttings) samples, exposed to varying concentrations of CO2 under in situ temperature and pressure conditions, yield valuable information with respect to water chemistry changes that could occur from a potential out-of-zone migration. Key field-measured groundwater monitoring parameters that change significantly in response to low levels of CO2 are pH (rapid decrease), alkalinity (increase), and conductivity (increase). Empirical models that predict soil gas concentrations using routinely measured climatic data such as air temperature, as well as models that predict the magnitude and duration of potential CO2 exposure in groundwater, should be employed as components of a broad surface and subsurface monitoring program.
Economic threshold of CO2-EOR and CO2 storage in the North Sea: A case study of the Claymore, Scott and Buzzard oil fields Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-08 Kris Welkenhuysen, Bruno Meyvis, Rudy Swennen, Kris Piessens
CO2-enhanced oil recovery in the North Sea can provide additional oil revenues, prolong the productive lifetime of oil fields, and potentially catalyse the large-scale deployment of CO2 geological storage. Under the current low oil prices, around and below 50 €/bbl, the investment is more difficult to justify. Here we show three case studies for the Claymore, Scott and Buzzard fields offshore of Scotland. A techno-economic assessment is made with the PSS IV simulator considering a low oil price scenario, market uncertainties and geological uncertainty. Stochastic parameters and project flexibility are used to simulate realistic project decisions. The Modified Internal Rate of Return (MIRR) is introduced as a performance indicator in combination with hurdle rate scenarios of 10, 11 and 12% for risk compensation. The possibility of continuing the storage of CO2 after oil production has stopped is considered, and reservoir uncertainty is introduced as stochastic parameters defining the EOR production profile. In terms of total value and development probability, the Buzzard field has the highest potential for a successful CO2-EOR project in all of the simulated scenarios, followed by Claymore and Scott. When compensating for field size, the Buzzard field still has the highest value per barrel of additionally produced oil, but the Scott field has a higher efficiency compared to Claymore. With an increase of the hurdle rate, the probability on investment in CO2-EOR decreases, but the probability on a profitable project increases. It also becomes more likely that if an EOR project is started, it will be followed by a CO2 storage phase. A hurdle rate of 12% even completely offsets the financial risk under the simulated conditions.
Shale-brine-CO2 interactions and the long-term stability of carbonate-rich shale caprock Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-07 A.G. Ilgen, M. Aman, D.N. Espinoza, M.A. Rodriguez, J.M. Griego, T.A. Dewers, J.D. Feldman, T.A. Stewart, R.C. Choens, J. Wilson
The success of geological carbon storage (GCS) depends on the sealing properties of caprocks, typically mudrocks, and their laminated variety – shales. In this study, we examined mineralogical changes in carbonate-rich Mancos Shale and corresponding changes in micro-mechanical properties following the reaction with carbon dioxide (CO2). Mineralogical changes of Mancos Shale depended on the pressure of CO2 during its exposure to the CO2-brine mixtures for up to 8 weeks. Dedolomitization was observed in the reactors pressurized with 100 psi of CO2, combined with the precipitation of gypsum. In the reactor pressurized with 2500 psi of CO2, the complete dissolution of calcite, partial dissolution of dolomite, and precipitation of magnesite and anhydrite were observed. Localized mechanical weakening was observed only for dolomite-muscovite-illite-rich laminae following whole shale puck alteration at 2500 psi of CO2, and a decrease of up to 50 ± 20% in scratch toughness was observed. The quartz-calcite-rich laminae did not exhibit a measurable difference in scratch toughness before and after reaction in CO2-rich brine. The predicted changes in mineralogy, porosity, density, and hardness of Mancos Shale are limited, according to the geochemical models describing alteration of shale by CO2-rich brine lasting for 5000 years. This study illustrates a coupled and localized chemical-mechanical response of caprock to the injection of CO2.
A screening-level life cycle greenhouse gas analysis of CO2 enhanced oil recovery with CO2 sourced from the Shute Creek natural gas-processing facility Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-05 Melanie D. Jensen, Nicholas D. Azzolina, Steven M. Schlasner, John A. Hamling, Scott C. Ayash, Charles D. Gorecki
This life cycle analysis (LCA) evaluates life cycle greenhouse gas (GHG) emissions associated with a system that produces both natural gas and crude oil. Two systems are defined: System 1, which independently produces natural gas and oil, and System 2, which captures carbon dioxide (CO2) from the natural gas-processing plant and utilizes this captured CO2 for enhanced oil recovery (EOR). The LCA uses customized spreadsheet models with emission factors from peer-reviewed literature and publications of the National Energy Technology Laboratory of the U.S. Department of Energy. The modeling results show that the CO2 EOR scenario using captured CO2 produces both natural gas and oil with lower life cycle GHG emissions than alternative systems producing natural gas and oil independently. Sensitivity analyses show that the model results are most sensitive to the fraction of CO2 captured (or equivalently, the fraction of CO2 vented) at the natural gas-processing facility and the incremental oil recovery factor and net CO2 utilization factor of the EOR operations. The input variable driving the relative difference in life cycle GHG emissions between these two systems is the fraction of CO2 captured at the natural gas-processing facility (i.e., the capture rate). The results of this study highlight the necessity of linking processes in the life cycle modeling, as a change to one process can affect other processes within the coupled energy system comprised of natural gas and oil. In addition, this analysis shows, as prior work has also suggested, that CO2 EOR using captured anthropogenic CO2 provides a viable means for offsetting carbon emissions from oil production and combustion via the associated storage of CO2 that occurs incidentally during this tertiary method of oil recovery.
A novel experimental apparatus for the study of low temperature regeneration CO2 capture solvents using hollow fibre membrane contactors Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-09-04 Tristan J. Simons, Peter Hield, Steven J. Pas
Influence of H2O phase state on system efficiency in O2/H2O combustion power plant Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-30 Yanlei Xiang, Lei Cai, Yanwen Guan, Wenbin Liu, Ying Liang, Yixiao Han, Yanguang Cao
In this work, oxy-fuel combustion with H2O as diluent in natural gas power plant is proposed, and the effect of phases of H2O on the overall system efficiency is investigated. Three different phase states of H2O, liquid water, steam and liquid-steam mixture are investigated, and the corresponding systems GST-L, GT-S and GT-M system are simulated and compared. To overcome the problem that the steam Rankin cycle cannot fully utilize the latent heat of water, the transcritical CO2 (T-CO2) cycle is introduced. The thermal analysis results show that the GT-M system with steam-water mixture as diluent performs the best, and the energy and exergy efficiency is 60.86% and 49.29%, respectively. The GST-L system takes the second place, and the GT-S system shows the lowest efficiency. The results reveal that steam-water mixture is the best phase of H2O recycled to control the combustion temperature, and the integration of gas turbine and T-CO2 cycle can fully utilize the thermal energy of flue gas to generate electricity. Therefore, the high-efficiency power generation with near-zero carbon emissions is achieved.
Structure-function, recyclability and calorimetry studies of CO2 adsorption on some amine modified Type I & Type II sorbents Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-30 Arindom Saha
CO2 adsorption was studied on different amines immobilized on silica, polymethyl methacrylate (PMMA) and mesoporous SBA-15 substrates. Hyperbranched polyethyleneimine (PEI) was impregnated onto silica and PMMA to generate Type I sorbents and their CO2 adsorption capacities were measured and compared to the respective unmodified supports. Amine-functionalized Type II sorbents were also synthesized by loading different amounts of a monoamine ((3-Aminopropyl) triethoxysilane), a diamine (N-[3-(Trimethoxysilyl) propyl] ethylenediamine) and a triamine (N1-(3-Trimethoxysilylpropyl) diethylenetriamine) onto mesoporous SBA-15 using grafting techniques. Nitrogen physisorption studies, surface density measurements and low angle XRD plots indicated a progressive filling of SBA-15 pores with increase in respective amine loadings. CO2 breakthrough studies conducted on PEI impregnated silica and PMMA at 40 °C and 60 °C showed that the temperature strongly influenced the CO2 adsorption capacities. The amount of total CO2 captured on amine-grafted SBA-15 sorbents increased with rise in amine density and amine type in the order Triamine > Diamine > Monoamine. All recyclability studies on the amine-modified sorbents yielded consistent CO2 capture capacities over a period of 3–5 adsorption–regeneration cycles. Simultaneous determination of adsorption capacities and corresponding associated heats at important stages of a complete CO2 breakthrough run (under both dry & moist conditions) provided critical real-time insights into the adsorption process and can be used as an effective tool for screening potential sorbents.
Experimental investigation of injection pressure effects on fault reactivation for CO2 storage Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-31 Pierre Cerasi, Anna Stroisz, Eyvind Sønstebø, Sergey Stanchits, Volker Oye, Robert Bauer
Laboratory tests were conducted in a triaxial load frame with acoustic emission and transmission capability to investigate mechanisms that might be initiating the microseismicity experienced in CO2 injection operations. Although often related to reactivation of mapped faults or local fracturing due to reduced injectivity, the case of the Illinois Basin – Decatur Project is used here to illustrate the need for better understanding of what triggers microseismic events in relatively large permeability, good reservoir candidates. There, microseismicity has occurred in the CO2 storage target formation, the Mt. Simon sandstone, as well as in the underlying Precambrian basement. The microseismicity in the Mt. Simon sandstone occurred ahead of CO2 plume arrival and at relatively low injection pressure conditions, well below the fracturing pressure at the injection well. A hypothesis is suggested for the occurrence of such events in the field, whereby critically stressed planes are activated by the passage of the pressure front at injection start; these faults are small and thus not visible in the seismic survey. In order to test this hypothesis, sandstone plugs were prepared by two different methods to incorporate a fracture plane, which we attempted to reactivate by pore pressure pulses. The reactivation was successful at low pressure for a fracture created in the laboratory at reservoir conditions but was unsuccessful except at a much higher pore pressure in a saw-cut artificial fracture. The results suggest that tortuous, rough stress-induced fractures may be easier to reactivate because of the higher probability that sections are already favorably oriented with respect to critical shear stress at a low pore pressure increase. Saw-cut fractures may close completely under isotropic stress loading and may be difficult to activate unless exactly oriented with respect to critical shear stress at a low pore pressure increase. Acoustic emission accompanying fracture reactivation was also recorded and analyzed. This revealed a different event distribution energy between creating and reactivating the fracture.
The role of natural fractures of finite double-porosity aquifers on diffusive leakage of brine during geological storage of CO2 Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-29 Morteza Dejam, Hassan Hassanzadeh
CO2-brine-rock interactions: The effect of impurities on grain size distribution and reservoir permeability Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-25 Mohammed D. Aminu, Seyed Ali Nabavi, Vasilije Manovic
The Bunter Sandstone formation in the UK’s southern North Sea has been identified as having the potential to store large volumes of CO2. Prior to injection, CO2 is captured with certain amounts of impurities, usually less than 5%vol. The dissolution of these impurities in formation water can cause chemical reactions between CO2, brine, and rock, which can affect the reservoir quality by altering properties such as permeability. In this study, we explored the effect of CO2 and impurities (NO2, SO2, H2S) on reservoir permeability by measuring changes in grain size distributions after a prolonged period of 9 months, simulating in situ experimental conditions. It was found that the effects of pure CO2 and CO2-H2S are relatively small, i.e., CO2 increased permeability by 5.5% and CO2-H2S decreased it by 5.5%. Also, CO2-SO2 slightly decreased permeability by 6.25%, while CO2-NO2 showed the most pronounced effect, reducing permeability by 41.6%. The decrease in permeability showed a correlation with decreasing pH of the formation water and this equally correlates with a decrease in geometric mean of the grain diameter. The findings from this study are aimed to be used in future modelling studies on reservoir performance during injection and storage, which also should account for the shifts in boundaries in the CO2 phase diagram, altering the reservoir properties and affecting the cost of storage.
Time-lapse analysis of pressure transients due to ocean tides for estimating CO2 saturation changes Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-23 Kozo Sato, Roland N. Horne
This study proposed and examined a practical technique for analysing CO2 storage responses using offshore pressure transients affected by the ocean tide. The gravitational attractions of the solar-system bodies cause ocean tides, and the pore pressure exhibits diurnal and semidiurnal fluctuations in response to such tidal phenomena. The pressure-fluctuation amplitude is related to the loading efficiency, which is a function of reservoir elastic properties and fluid saturations. Therefore, the loading efficiency can be used to estimate the in situ pore compressibility and the CO2 saturation. Applying the tidal-signal analysis in a time-lapse manner, one may see temporal changes in CO2 saturation and consequently describe the dynamic behavior of sequestered CO2. In the analysis at the offshore CO2 storage site in Tomakomai, Japan, a temporal decrease in CO2 saturation was detected during the shut-in period, which is caused primarily by CO2 migration away from the well. The proposed methodology essentially requires only continuous pressure data, which are routinely available during CO2 storage operations, and thus, can be a cost-effective and labour-saving monitoring technique.
CFD modeling of CO2 capture by water-based nanofluids using hollow fiber membrane contactor Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-22 Nasibeh Hajilary, Mashallah Rezakazemi
A two-dimensional (2D) model was developed for CO2 removal from a gas mixture using a hollow fiber membrane contactor. Nanofluids of silica and carbon nanotube (CNT) nanoparticles were used as absorbents. The governing equations were solved using computational fluid dynamics technique (CFD). The results of the model were compared with the experimental data and good agreements confirmed the validity of the developed mass transfer model. The results showed that increasing absorbent flowrate enhances the CO2 absorption rate, especially at a low flowrate. The performance of CNT nanofluids is much better than nanosilica. At high liquid flowrate (40 L/h) CNT captures CO2 up to 53.53% while nanosilica captures 37.38%. Also, an increase in the concentration of CNT nanofluid from 0.2 to 0.5 wt.% at a constant flowrate of 20 L/h leads to 20% increase in the CO2 separation while its enhance for nanosilica is 16%.
Towards ‘green’ geothermal energy: Co-mineralization of carbon and sulfur in geothermal reservoirs Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-23 Chiara Marieni, Jan Přikryl, Edda Sif Aradóttir, Ingvi Gunnarsson, Andri Stefánsson
The role of carbon capture and storage electricity in attaining 1.5 and 2 °C Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-22 Adriano Vinca, Marianna Rottoli, Giacomo Marangoni, Massimo Tavoni
The climate targets defined under the Paris agreement of limiting global temperature increase below 1.5 or 2 °C require massive deployment of low-carbon options in the energy mix, which is currently dominated by fossil fuels. Scenarios suggest that Carbon Capture and Storage (CCS) might play a central role in this transformation, but CCS deployment is stagnating and doubts remain about its techno-economic feasibility. In this article, we carry out a throughout assessment of the role of CCS electricity for a variety of temperature targets, from 1.5 to above 4 °C, with particular attention to the lower end of this range. We collect the latest data on CCS economic and technological future prospects to accurately represent several types of CCS plants in the WITCH energy-economy model, We capture uncertainties by means of extensive sensitivity analysis in parameters regarding plants technical aspects, as well as costs and technological progress. Our research suggests that stringent temperature scenarios constrain fossil fuel CCS based deployment, which is maximum for medium policy targets. On the other hand, Biomass CCS, along with renewables, increases with the temperature stringency. Moreover, the relative importance of cost and performance parameters change with the climate target. Cost uncertainty matters in less stringent policy cases, whereas performance matters for lower temperature targets.
Local capillary trapping in carbon sequestration: Parametric study and implications for leakage assessment Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-21 Bo Ren
Local capillary trapping (LCT) is the trapping of CO2 by local capillary barriers. It occurs during buoyancy-driven migration of bulk phase CO2 within a saline aquifer exhibiting spatially varying properties (permeability and capillary entry pressure). The benefit of LCT, in the context of CO2 sequestration, is that local capillary trapped CO2 is not susceptible to leakage through failed seals. However, it is unclear how the petrophsyical/geological properties and flow dynamics influence LCT. Thus, the objective of this work is to evaluate the degree to which potential local capillary traps are filled and quantify the extent of immobilization persisting after loss of seal integrity. This paper presents a systematic and thorough study of the influential parameters of LCT. Fine-scale capillary pressure fields are generated by using geostatistical permeability realizations and applying the Leverett j-function. Multiple factors are examined, including injection rate, anisotropy, formation dip, aquifer types, residual gas saturation, and capillary hysteresis. Leakage representative of wellbore failure is simulated, and LCT after leakage is evaluated and compared to other trapping mechanisms. The results show that local capillary traps in the near-well region can be fully filled during injection. Moreover, they remain filled after post-injection buoyancy-driven flow ends. The filling efficiency of local capillary traps increases with the decrease in gravity number (ratio of buoyant force over viscous force). As a result, maximizing LCT in carbon sequestration in porous reservoirs may be achievable with the implementation of appropriate injection strategies.
Viability of foam to enhance capillary trapping of CO2 in saline aquifers—An experimental investigation Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-20 Abdulrauf Rasheed Adebayo
Capillary trapping is one of the quickest mechanism by which carbon dioxide (CO2) is trapped during geological sequestration. It is also of the most immediate importance because a significant fraction of the injected CO2 can be stored and rendered immobile in the event of a leak. Many research papers have been published in the past decade focusing on improving capillary trapping of CO2 during geological sequestration. In this study, a different approach was investigated, which involved the use of colloidal materials to enhance capillary trapping of CO2 during sequestration in saline aquifers. A suite of reservoir condition laboratory experiments was conducted on some selected reservoir rock samples saturated with synthetic brine to mimic actual saline aquifers. A foaming agent (0.025% wt. nonionic surfactant) was dissolved in the brine. Foams were then generated in the rock samples by alternate injection of gas and brine using a coreflooding setup. An electrical resistivity measuring tool attached to the setup was used for real-time and in-situ tracking of pore-scale events such as gas movement, capillary trapping of gas, and the stability of the trapped gas. Both Nitrogen (N2) and CO2 gases were investigated and the results showed a tremendous increase in the amount of trapped N2 and CO2 gases when foams were applied compared to gas injection without foams. However, low interfacial tension between CO2 and the surfactant solution affected the viability of foams in trapping CO2. Nevertheless, the use of CO2 foam stabilizers is promising in addressing this challenge. The methodology described in this paper can be used to test the efficiency of a variety of CO2 foam stabilizing agents that may be developed.
Using sodium thiosulphate for carbon steel corrosion protection against monoethanolamine and 2-amino-2-methyl-1-propanol Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-20 Samara A. Sadeek, Daryl R. Williams, Kyra L. Sedransk Campbell
The corrosion performance of carbon steel (C1018) with inhibitor sodium thiosulphate (STS) has been compared to C1018 (without an inhibitor) and stainless steel (SS316 L) at 80 and 120 °C to determine the feasibility of use in a post-combustion CO2 capture plant (PCCC). The corrosivity of variable ratio monoethanolamine (MEA) and 2-amino-2-methyl-1-propanol (AMP) aqueous solvent blends were assessed after seven days using a gravimetric method for mass change, Fe ion solution concentration (ICP–OES), surface imaging (SEM) and analytical techniques (EDX and XRD). At low concentrations of MEA (25%), the use of the corrosion inhibitor is ineffective as it prevents the formation of protective films naturally developed by AMP. The performance of the inhibitor with MEA–AMP blends was noteworthy at higher MEA concentrations of 50 and 75%. In these cases, reduced corrosion rates were observed through gravimetric and ICP analyses. Imaging by SEM showed reduced surface corrosion and adsorption of STS-derived species. Since these higher MEA concentration solutions offer better CO2 loadings, but still some exhibit corrosive effects when used alone on carbon steel, the use of STS can facilitate an economical usage of carbon steel for PCCC plants.
Carbon capture and storage (CCS) experts’ attitudes to and experience with public engagement Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-17 Dimitrios Xenias, Lorraine Whitmarsh
Carbon capture and storage (CCS) is widely seen as a key technology for mitigating climate change. Public engagement with CCS is important for a range of reasons, but previous work has not explored the perceived rationales for, or benefits of, public engagement amongst CCS experts (including those who engage the public themselves). Here, we present mixed-methods research (comprising expert interviews and an online survey) to elucidate these rationales, and expose CCS expert views of public engagement. Our findings indicate some differences in perceptions of public engagement with CCS (and of the risks and benefits of CCS) between those who engage directly with the public and those who do not: the former tend to have a more nuanced view of engagement, and are also more enthusiastic about the benefits of CCS, than the latter. Overall, CCS experts recognise the importance of public engagement for the roll-out of CCS for both substantive and instrumental rationales, and are largely aware of the range of factors (knowledge, values, trust, etc.) influencing public engagement. Nevertheless, the relatively low salience of early and substantive engagement amongst CCS experts suggests there is room for improving the flow of learning from the public engagement research literature to those charged with delivering it.
Optimum storage depths for structural CO2 trapping Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-15 Stefan Iglauer
Structural trapping is the primary CO2 geo-storage mechanism, and it has historically been quantified by CO2 column heights, which can be permanently immobilized beneath a caprock, using a buoyancy force-capillary force balance. However, the high dependence of CO2-wettability (a key parameter in the above analysis) on pressure and temperature – and thus storage depth – has not been taken into account. Importantly, rock can be CO2-wet at high pressure, and this wettability reversal results in zero structural trapping below a certain storage depth (∼2400 m maximum caprock depth for a most likely scenario is estimated here). Furthermore, more relevant than the CO2 column height is the actual mass of CO2 which can be stored by structural trapping (mCO2). This aspect has now been quantified here, and importantly, mCO2 goes through a maximum at ∼1300 m depth, thus there exists an optimal storage depth at around 1300 m depth.
Assessment of the potential carbon footprint of engineered processes for the mineral carbonation of PGM tailings Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-14 M.S. Ncongwane, J.L. Broadhurst, J. Petersen
The engineered sequestration of carbon dioxide (CO2) emissions through mineral carbonation typically requires energy intensive conditions and chemical reagents to accelerate the naturally slow reaction processes. In order to be an effective carbon dioxide mitigation strategy, engineered mineral carbonation processes have to result in a net reduction of CO2 emissions. This is particularly the case for feedstock such as platinum group metal (PGM) tailings, which are comprised largely of the relatively inert pyroxene mineral. This study evaluated the viability of using these tailings for carbon sequestration through mineral carbonation on the basis of an assessment of the potential carbon footprint of selected engineered processes. The processes selected include the ammonium salts process, the direct aqueous process, the Åbo Akademi University (ÅAU) multi-stage gas-solid route, a mineral acid pH swing process and Lackner’s multi-stage HCl extraction process. Aspen Plus v8 software was used for mass and energy balance modelling, whilst the Life Cycle Assessment (LCA) software programme SimaPro v7.7.3 was used for carbon emissions accounting. The selected processes all resulted in higher emissions of carbon dioxide than those sequestered. This was particularly the case for Lackner’s multi stage HCl process (18 295 kg-CO2e) and the indirect aqueous ammonium salts (8 798 kg-CO2e) processes. The process having the lowest carbon footprint was the ÅAU process (1 354 kg-CO2e), followed by the direct aqueous process (2 364 kg-CO2e) and the mineral acid pH swing (3 126 kg-CO2e). The unit processes making the most significant contribution to the carbon footprint of the mineral carbonation process systems are heat requirements and chemical reagent make-up. Sensitivity analysis shows that the direct aqueous and ÅAU process emissions can be reduced beyond the CO2 emissions threshold when conversion is increased.
Characterization and quantification of a CO2 and CH4 leakage experiment from a well into the carbonate vadose zone Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-11 Kévins Rhino, Corinne Loisy, Adrian Cerepi, Bruno Garcia, Virgile Rouchon, Aïcha El Khamlichi, Sonia Noirez
An ultra-diffusive leakage experiment was performed on the pilot site of Saint-Emilion near Bordeaux in France. It consisted in the injection of 85% CO2 and 5% of each He, Kr and CH4 in a vertical well with a very low injection pressure. This study allowed the development of an automated tool that continuously monitored the gas phase within the vadose zone. Measurements showed that the gas plume had a heterogeneous spatial and temporal variation. Mathematical calculations performed on the time series of the gas species showed that diffusive transport mainly occurred in the porous media. However, every stage of the migration could not be driven by diffusive process as shown by the exponential regression. A non-identified transport mechanism may have occurred during the increase of concentration. He was proven to be a suitable temporal tracer for a CO2 leakage as it was a good temporal precursor. Even if the process was weaker than in the former injection experiments, Kr could show help foreseeing the extent of the gas plume within the pilot site. CH4 was also shown to be an excellent temporal precursor of CO2 arrival. The amount of gas migrating through the preferential path identified in the previous experiment was weaker than in the previous study. Moreover, the monitoring showed that a significant amount of injected gas migrated deeper in the vadose zone. The ratios CO2/Kr vs. CO2/He and the evolution of CO2/Kr, CO2/He and CO2/CH4 put in evidence three groups of probes. The first consists in the subsurface probes and is characterized by a potential reactive transport of CO2 through the vadose zone such as gas dissolution in the aqueous phase. The second group gathers the closest probes to the injection point and underlines a very slow return to baseline value through diffusion. The third group is characterized by a competition between the process occurring in the first and second group. Isotopic measurement of Kr could not bring relevant information about the CO2 fates into the vadose zone. However, it shows the possible presence of mechanism transport such as vertical flux and gravitational settlings. Observations from both of all the leakage experiment and future laboratory experiment could improve our understandings of the buffering zone and help to foresee CO2 leakage for future storage site.
Renewable aqueous ammonia from biogas slurry for carbon capture: Chemical composition and CO2 absorption rate Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-07 Qingyao He, Long Ji, Bing Yu, Shuiping Yan, Yanlin Zhang, Shuaifei Zhao
Aspen Plus supported analysis of the post-combustion CO2 capture by chemical absorption using the [P2228][CNPyr] and [P66614][CNPyr]AHA Ionic Liquids Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-06 J. de Riva, V. Ferro, C. Moya, M.A. Stadtherr, J.F. Brennecke, J. Palomar
In this work, the post-combustion CO2 chemical capture using the [P2228][CNPyr] and the [P66614][CNPyr] Aprotic Heterocyclic Anion Ionic Liquids (AHA ILs) is analyzed. To model the unit operations in the Aspen Plus commercial process simulator, a multiscale a priori COSMO-based methodology developed in our group able to include the AHA IL into the simulator database is used. This methodology takes advantages of combined quantum chemistry and statistical thermodynamics (COSMO-RS) to predict the component properties needed to include new non-databank compounds into the AspenOne process simulator suite. In Aspen Plus, the CO2 capture process to treat a multicomponent flue gas by chemical absorption is modeled. The absorption operation is simulated using the RADFRAC rigorous model of a commercial packed column both in Rate-based (mass transfer limitations considered) and Equilibrium modes. The heat of reaction and the mass transfer kinetics are considered to properly model the absorption efficiency at isothermal and adiabatic operating conditions. Tetraglyme is proposed as a co-solvent able to both improve the concentration of CO2 present in the liquid phase and minimize the mass transfer limitations. Afterward, the multicomponent desorption (CO2 and H2O must be desorbed) is analyzed at 115 °C and 1 bar. A recirculation of CO2 is proposed as stripping fluid able to reduce water partial pressure and, therefore, improve the water desorption. The complete CO2 capture process is then simulated analyzing the recycled water effects and recalculating the solvent needs. Finally, the energy and solvent expenses are compared to other CO2 capture technologies proposed in the literature.
Facilitated transport membranes with an amino acid salt for highly efficient CO2 separation Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-04 Haiyang Zhang, Hailong Tian, Jinli Zhang, Ruili Guo, Xueqin Li
Simultaneous absorption of carbon dioxide and nitrogen dioxide from simulated flue gas stream using gas-liquid membrane contacting system Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-03 Jalil Ghobadi, David Ramirez, Shooka Khoramfar, Robert Jerman, Michele Crane, Kenneth Hobbs
Membrane gas contactors are a promising alternative to conventional post-combustion carbon capture technologies. However, residuals of the other acid gas compounds can exist in the flue gas streams emitted from industrial facilities, having a notable impact on the absorption performance of the membrane system. Simultaneous removal of CO2 and NO2 from a simulated flue gas stream was carried out in a polytetrafluoroethylene (PTFE) hollow fiber gas-liquid membrane contacting (GLMC) system using different scrubbing solutions. A series of experiments were conducted to study the effects of operating conditions such as gas and liquid cross flow velocities, concentration of feed gas, absorbent nature and concentration, and long-term performance of the GLMC system on the removal efficiencies as well as mass transfer rates of CO2 and NO2. Experimental results indicated that simultaneous absorption of CO2 and NO2 were enhanced with increasing the liquid-phase cross flow velocity, decreasing gas-phase cross flow velocity, and using chemical stripping absorbents. Moreover, it was shown the sodium hydroxide to be a superior absorbent as compared to alkanolamine solutions for the co-capture of CO2 and NO2 species. It was observed that low concentrations of NO2 in the feed gas had a minimal impact on the decarbonization of GLMC system. The durability of the membrane system was also evaluated by running the simultaneous gas removal experiments over a 24-h period. The consistency of the absorption efficiency results confirmed the potential of using PTFE membrane system for the simultaneous absorption of CO2 and NO2 gases.
Techno-economic comparative analysis of Biomass Integrated Gasification Combined Cycles with and without CO2 capture Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-02 Guiyan Zang, Junxi Jia, Sharma Tejasvi, Albert Ratner, Electo Silva Lora
Biomass Integrated Gasification Combined Cycle (BIGCC) power system is a potential application of biomass gasification technology to control CO2 emissions from power generation processes. Nevertheless, there is no study of BIGCC systems that provides detailed techno-economic comparative among its different technological alternatives. This study provides the techno-economic comparative analysis of eight BIGCC system designs that include the technology options of the biomass gasification, the power generation, and the CO2 emission control. Results show that the Levelized Cost of Electricity (LCOE) of these systems is ranged from 13.1 ¢/kWh to 25.9¢/kWh. For current designs, the Selexol CO2 removal technology is more economical than the MEA CO2 capture process. Furthermore, when the biomass price is lower than 10 $/ton, the air gasification BIGCC systems can compete with the current electricity generation technology, whereas when the CO2 emission price is higher than 90 $/ton, the additional CO2 Capture and Storage technology has the potential to reduce the LCOE of BIGCC systems. Moreover, the sensitivity analysis estimates the impacts of other key economic parameters on the LCOE and Monte Carlo method is used to show the uncertainty of simulation.
Trapping of buoyancy-driven CO2 during imbibition Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-02 Niels Bech, Peter Frykman
This paper presents a simulation study on the influence of rock heterogeneity on the distribution and magnitude of trapped CO2 resulting from a drainage/imbibition sequence in a saline aquifer with buoyant CO2. Four scenarios are studied, three simple 1D cases and a 2D case with heterogeneity derived from realistic architecture inspired by tidal sand deposits, having combined layering and crossbedding and sediment property contrasts. The four cases are examined in order to understand which underlying mechanisms are responsible for the results observed and therefore also which processes it is necessary to reflect in the simulation procedure. It is shown that it is important to take into account hysteresis in the capillary pressure. During the imbibition the capillary pressure decreases and the ability to capillary trap the CO2 is reduced and it may in some cases completely vanish. Thus, the capillary pressure hysteresis has a major impact on the amount of trapped CO2. If the imbibition curve has a threshold pressure the sealing power of the barrier is not completely lost, which leads to hyper-trapping, characterised by mobile CO2 being trapped with above end-point saturations. If the imbibition capillary pressure reaches zero, only local barriers constituting effective seals are able to trap free and potentially mobile CO2 and the trapping mechanism is exactly the same as the one acting beneath the top seal. The neglection of capillary pressure hysteresis may result in a large overestimation of the amount of trapped CO2.
China baseline coal-fired power plant with post-combustion CO2 capture: 1. Definitions and performance Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-02 Qian Cui, Haoren Lu, Chufu Li, Surinder Singh, Liming Ba, Xinglei Zhao, Anthony Y. Ku
Global efforts to advance CO2 capture technologies have produced a strong base of field experience and modeling capability to inform efforts to deploy this technology in China. For example, the U.S. Department of Energy has published bituminous coal baseline reference cases to provide a consistent set of assumptions for modeling the performance of coal power plants equipped with CO2 capture technology in the United States. In China, there are some important features of power plant construction and operation, such as dry cooling in some plants, different grade coal, and low load operation, that must be accounted for in analyzing the performance of CO2 capture-enabled power plants. Moreover, unique aspects of the policy landscape in China, such as an openness to partial capture solutions in the near-term, introduce some flexibility in deployment strategy. In this study, we analyze the impacts of these features on plant performance and we propose a set of “baseline China plants” based on industrial experience to serve as reference cases for analyzing deployment scenarios for post-combustion CO2 capture at coal-fired power plants in China. This paper focuses specifically on the performance aspects of the technoeconomic analysis. Costs are addressed in a companion paper. The most significant factors responsible for differences in power plant efficiency were fuel quality and differences in steam cycle hardware and operation. The impact of dry cooling was also significant. Our reference cases are broadly consistent with previous studies of this topic and help to clarify the contributions of different factors when comparing the performance of CO2 capture for power plants in the US and China.
Formation of an amorphous silica gel barrier under CO2 storage conditions Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-02 C.A. Castañeda-Herrera, J.R. Black, E.M. Llanos, G.W. Stevens, R.R. Haese
Risk assessments of Carbon Capture and Storage (CCS) have identified that in some instances carbon dioxide (CO2) leakage through the caprock cannot be entirely precluded, e.g. through high permeability undetected zones. This study recommends the use of a geochemical barrier that forms upon reaction with CO2, as a means to mitigate and remediate CO2 leakage. The proposed technology is based on the injection of an alkaline sodium silicate solution that reacts with the leaking CO2, leading to silica gel formation. Laboratory studies undertaken to evaluate this technology, included flow-through and core-flood experiments at ambient and reservoir conditions, respectively. The tests aim was to assess the barrier formation performance by changes in pressure as an indicator of permeability reduction. Results show that the formation of the silica barrier was controlled by the mixing gradient of the two reactants, where the reaction resulted in a permeability reduction between one and three orders of magnitude under reservoir conditions. Thus, using sodium silicate as a reagent for forming a barrier is a promising technology to abate CO2 leakage for CCS purposes. Further research using reactive transport modelling to investigate barrier formation in a reservoir model is needed before applying this technology at the field scale.
Evaluation of the potentiality and suitability for CO2 geological storage in the Junggar Basin, northwestern China Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-02 Zhaoxu Mi, Fugang Wang, Yongzhi Yang, Fang Wang, Ting Hu, Hailong Tian
CO2 geological storage is one of the most important methods for reducing the emissions of anthropogenic greenhouse gases into the atmosphere. Junggar Basin is an important energy base in China, with high CO2 emissions and geological storage potential. The evaluation of the suitability for CO2 geological storage is the basis for screening CO2 geological storage sites, and a scientific and effective evaluation method is key. Using the Junggar Basin as the study site, an indicator system consisting of 3 indicator layers and 27 indicators was constructed. By combining the analytic hierarchy process and fuzzy comprehensive evaluation method, the geological suitability for CO2 geological storage in 44 secondary tectonic units in the Junggar Basin was evaluated. The evaluation results provide a scientific basis for site selection and project construction for CO2 geological storage in the Junggar Basin.
Hydrate seal formation during laboratory CO2 injection in a cold aquifer Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-01 J. Gauteplass, S. Almenningen, G. Ersland, T. Barth
We report the flow resistance of liquid CO2 advancing through cold, water-saturated sandstone to mimic CO2 storage in a shallow aquifer. Sedimentary hydrate growth is determined by resistivity, temperature, and pressure measurements. Hydrate formation in the pore space resulted in significant pressure gradients and blockage of flow under most conditions. The effect of CO2 injection rate, initial water saturation, brine salinity, and temperature are investigated and discussed with respect to induction time and hydrate seal properties. We conclude that CO2 hydrates consistently form an effective and robust flow barrier in sandstone aquifer under local hydrate stable conditions. Rock permeability elimination, even at low initial water saturation (36%), indicates a pore-filling morphology of flow-induced CO2 hydrate. Flow discontinuity by hydrate formation is thus highly relevant as a sealing mechanism for storage of liquid CO2 near the base of the gas hydrate stability zone (GHSZ).
Techno-economic assessment of chemical looping reforming of natural gas for hydrogen production and power generation with integrated CO2 capture Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-01 Shareq Mohd Nazir, Joana Francisco Morgado, Olav Bolland, Rosa Quinta-Ferreira, Shahriar Amini
The current study presents the techno-economic analysis of the CLR-CC process. The CLR-CC process comprises of chemical looping reforming (CLR) of Natural Gas, water gas shift, CO2 capture and compression, and combined cycle power plant. A 1-D phenomenological model was developed using MATLAB and is used to study the performance of CLR, whereas the remaining part of the process was analysed using commercial software tools like Aspen and Thermoflow. The effect of design conditions in CLR, mainly the air flowrate to the oxidation reactor, oxidation reactor outlet temperature and the steam flowrate to the fuel reactor of CLR, on the overall techno-economic performance of the CLR-CC process is reported. The CH4 conversion in CLR, net electrical efficiency, CO2 avoidance rate and the Levelised Cost of Electricity (LCOE) have been identified as techno-economic performance indicators. For the sensitivity study carried out in this study through 12 cases, the net electrical efficiency of the CLR-CC process varies between 40.0 and 43.4%, whereas the LCOE varies between 75.3 and 144.8 $/MWh, which is highly dependent on the fuel cost and process contingency rates.
Laboratory determination of oil draining CO2 hysteresis effects during multiple floods of a conventional clastic oil reservoir Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-01 Steven A. Smith, Blaise A.F. Mibeck, John P. Hurley, Christopher J. Beddoe, Lu Jin, John A. Hamling, Charles D. Gorecki
Determination of hysteresis in relative permeability data is useful in obtaining more reliable predictions of water alternating gas (WAG) enhanced oil recovery performance and accompanying associated storage of CO2. A laboratory-based evaluation of CO2 draining oil has been conducted on reservoir rocks from a conventional clastic oil reservoir undergoing tertiary CO2 enhanced recovery. Experimentation was conducted at reservoir conditions of 16 MPa (2300 psi) and 43 °C (110 °F). Through this study, a better understanding of the oil production and associated storage of CO2 in a conventional clastic oil reservoir has been obtained. Data generated provide an example of a site-specific field project that is currently undergoing a tertiary CO2-based EOR project demonstrating that associated CO2 storage will occur. Through multiple cycles of CO2 injection, this study has shown the effectiveness of first contact CO2 as it relates to the mobilization of oil from injector to producer. Additionally, in this conventional clastic reservoir, CO2 trapping appears to have taken place during the initial imbibition cycle, as oil production and differential pressures remain consistent during subsequent tests.
Evaluation of low and high level integration options for carbon capture at an integrated iron and steel mill Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-08-01 Maria Sundqvist, Maximilian Biermann, Fredrik Normann, Mikael Larsson, Leif Nilsson
To achieve climate goals, the iron and steel industry needs to find energy efficient and cost saving pathways for implementing CO2 capture. This paper evaluates two integration alternatives of excess-heat powered CO2 capture at an integrated iron and steel plant using the concept of partial capture. The two sources of CO2 investigated were the blast furnace gas (BFG) and flue gas from the combined heat and power (CHP) plant, representing a high and low level integration alternative, respectively. An amine capture system was simulated in Aspen Plus, and optimized for low energy requirement. To analyze the effects on the iron and steel system and the level of available excess heat, an in-house model was used containing interlinked energy and mass balances of each process step available. The results show that high level integration of CO2 capture gives a lower specific heat demand and improves the overall energy efficiency of the steel plant, resulting in more available heat. For this reason, it is possible to capture 3% more from BFG without any extensive alterations to the plant to recover excess heat. The total available excess heat at the plant will sustain capture of up to 46% of the steel plants total CO2 emissions, and beyond that point steam has to be imported.
Effect of thermal stress on wellbore integrity during CO2 injection Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-31 Pratanu Roy, Joseph P. Morris, Stuart D.C. Walsh, Jaisree Iyer, Susan Carroll
Optimization of Carbon Dioxide Capture Using Sorbent-Loaded Hollow-Fiber Modules Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-30 Dhruv C. Hoysall, Matthew D. Determan, Srinivas Garimella, Richard D. Lenz, Daniel P. Leta
The performance of sorbent-loaded hollow-fiber modules to capture carbon dioxide from the exhaust stream of a thermal power plant is analyzed. The hollow-fiber modules undergo a Rapid Temperature Swing Adsorption (RTSA) process to capture carbon dioxide. A detailed heat and mass transfer model is developed to simulate the performance of the fiber module. The thermal wave technique for heat recovery is incorporated to reduce the thermal energy consumption and reduce operating costs. A parametric study of six key operating parameters is presented, and tradeoffs in performance metrics with variations in operating parameters are discussed. The proposed process compares favorably with other adsorption-based carbon capture technologies.
Quantitative risk assessment of offshore carbon dioxide injection system considering seismic effects Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-29 Younggeun Lee, Gunhak Lee, Jinjoo An, Kyeongsu Kim, Usama Ahmed, Chul-Jin Lee, Chonghun Han
Quantitative risk analysis (QRA) is one of the most generally used safety analysis measures for risk management in process industries. Currently, earthquakes occur worldwide, resulting in significant damage. Despite the importance of considering the danger of earthquakes, however, seismic effects are often not included in risk analysis owing to difficulties in considering the multi-hazard nature and domino effects of earthquakes. In this study, an improved methodology for QRA was proposed to consider the seismic effects including domino effects, and multi-hazard impacts of an earthquake by using a Bayesian network (BN). This analysis was applied to a topside CO2 injection system for underground storage, which is susceptible to seismic effects. Because frequency analysis is based on a causal relationship, the BN can be used to simultaneously consider domino effects and multi-hazard risks. As a result, the societal risk integral, one of the factors in risk analysis, was 9.667 × 10 - 4 / y e a r in modified QRA; this value shows an increase of 3.9% compared with the societal risk integral in conventional QRA. Furthermore, the value can be increased to 35% in the sensitivity analysis depending on annual exceedance probability (AEP). This result shows the importance of considering seismic effects, including both the domino effect and multi-hazard impacts, in QRA. A risk reduction method was additionally applied to mitigate the process risk.
Monitoring of the blend 1-methylpiperazine/piperazine/water for post-combustion CO2 capture. Part 1: Identification and quantification of degradation products Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-27 Lorena Cuccia, Nihel Bekhti, José Dugay, Domitille Bontemps, Myriam Louis-Louisy, Thierry Morand, Véronique Bellosta, Jérôme Vial
Post-combustion CO2 capture process using amine solvents is limited by the high energy penalty and the irreversible degradation of amines. The present work aimed at studying the degradation of the innovative blend 1-methylpiperazine/piperazine (1MPZ/PZ: 30/10%wt.) in a lab-scale pilot plant, LEMEDES-CO2, with conditions representative of post-combustion CO2 capture for power generation. Degradation of the solvent was realized twice during 800 and 955 h. Addition of acidic impurities (H2SO3 and HNO3) in the second campaign was performed in order to study their impact on the solvents degradation. CO2 loadings were determined and showed an average value of 0.28 for the lean solvent and 0.63 for the rich solvent. In order to identify and quantify degradation products, complementary analytical strategies were developed involving LC–MS, ionic chromatography and GC–MS. In order to monitor the gaseous effluents, a sampling on solid sorbents (Tenax® TA) was performed followed by thermodesorption and GC–MS analysis. This study permitted the identification of 23 degradation products in the liquid phase of the solvent, and 16 emitted with the treated flue gas. Among them were found piperazine derivatives, alkylpyrazines and organic acids. Quantification was performed on both liquid and gaseous phases on 10 selected compounds.
NOX formation in oxy-fuel combustion of lignite in a bubbling fluidized bed – Modelling and experimental verification Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-26 Matěj Vodička, Nils Erland Haugen, Andrea Gruber, Jan Hrdlička
This paper reports results of experimental and numerical studies of NOx formation in a 30 kWth lab-scale bubbling fluidized bed running in oxy-fuel mode. The numerical model is based on the GRI-mech 3.0 mechanism to compute the kinetics of homogeneous reactions of volatiles and char combustion products and takes into account the flue gas recirculation. The impact of the oxygen excess and of the fluidized bed temperature was examined. Both the numerical simulations and the experiments shown a significant correlation of NOX formation with the excess of oxygen, where a higher oxygen concentration enhances the fuel-bound nitrogen oxidation to NOX. It was also found that there is no correlation of the NOx formation and resulting emissions with the fluidized bed temperature in temperature range typical for bubbling fluidized bed combustors (840–960 °C), but the numerical simulations showed an increased NOX concentration when the temperature raised more (up to 1360 °C). The agreement of experimental and numerical results shows that the numerical model can provide useful insight into the mechanism of NOX formation.
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