Natural analogue of the rise and dissolution of liquid CO2 in the ocean

The behavior of natural carbon dioxide (CO₂) droplets (8–10 mm in diameter) were observed in a seafloor hydrothermal system at the Okinawa Trough. The natural CO₂ droplet contain 95–98% of CO₂, 2–3% of H₂S, and other gas species. The ascending CO₂ droplets were tracked by a remotely operated vehicle (ROV), and depth, temperature, salinity, pH and partial pressure of CO₂ (pCO₂) in seawater near the CO₂ droplets were measured during droplet ascent by a conductivity-temperature-depth sensor (CTD) and in situ pH/pCO₂ sensor. The visual images of the rising CO₂ droplets were recorded with a high definition television camera on the ROV. A mapping survey (400 m × 400 m; 4 horizontal layers) revealed a dominant distribution of low pH area over the natural CO₂ venting site. The size and rise rate of CO₂ droplets decreased during their ascent in the water column from depths of 1424 to 679 m (a tracking interval of 745 m). The CO₂ droplets dissolved gradually to become small flakes of CO₂ hydrate while rising, and these ascending flakes were found to disappear at 679 m depth. Although a pH as low as 5 was detected just above the liquid CO₂ venting site on the seafloor, no detectable pH depression in the water column ambient to the rising CO₂ droplets was observed. The results of the pH mapping survey showed only localized pH depression over the CO₂ venting site.     

Experimental investigation of the CO2 sealing efficiency of caprocks

Using a combination of experimental (petrophysical and mineralogical) methods, the effects of high-pressure CO₂ exposure on fluid transport properties and mineralogical composition of two pelitic caprocks, a limestone and a clay-rich marl lithotype have been studied. Single and multiphase permeability tests, gas breakthrough and diffusion experiments were conducted under in situ p/T conditions on cylindrical plugs (28.5 mm diameter, 10–20 mm thickness).The capillary CO₂ sealing efficiency of the initially water-saturated sample plugs was found to decrease in repetitive gas breakthrough experiments on the same sample from 0.74 to 0.41 MPa for the limestone and from 0.64 to 0.43 MPa for the marl. Helium breakthrough experiments before and after the CO₂ tests showed a decrease in capillary threshold (snap-off) pressure from 1.81 to 0.62 MPa for the limestone.Repetitive CO₂ diffusion experiments on the marlstone revealed an increase in the effective diffusion coefficient from 7.8 × 10^?11 to 1.2 × 10^?10 m².Single-phase (water) permeability coefficients derived from steady-state permeability tests ranged between 7 and 56 nano-Darcy and showed a consistent increase after each CO₂ test cycle. Effective gas permeabilities were generally one order of magnitude lower than water permeabilities and exhibit the same trend. XRD measurements performed before and after exposure to CO₂ did not reveal any distinct change in the mineral composition for both samples. Similarly, no significant changes were observed in specific surface areas (determined by BET) and pore-size distributions (determined by mercury injection porosimetry). High-pressure CO₂ sorption experiments on powdered samples revealed significant CO₂ sorption capacities of 0.27 and 0.14 mmol/g for the marlstone and the limestone, respectively.The changes in transport parameters in the absence of detectable mineral alterations may be explained by carbonate dissolution and further precipitation along a pH profile across the sample plug which would not be subject to quantitative mineral alteration.     

Ionic liquids for post-combustion CO2 absorption

The present work is a study to evaluate ionic liquids as a potential solvent for post-combustion CO₂ capture. In order to enhance the absorption performance of a CO₂ capture unit, different ionic liquids have been designed and tested. The main goal was to get a comparison between a reference liquid and selected ionic liquids. As the reference, a solution of 30 w% monoethanolamine (MEA) and water was used. A large range of different pure and diluted ionic liquids was tested with a special screening process to gain general information about the CO₂ absorption performance. Based on these results, a 60 w% ionic liquid solution in water was selected and the vapour–liquid equilibrium was measured experimentally between 40 °C and 110 °C. From these curves the enthalpy of absorption for capturing CO₂ into the ionic liquid was determined. With these important parameters one is able to calculate the total energy demand for stripping of CO₂ from the loaded solvent for comparison of the ionic liquid based solvent with the reference MEA solvent. The energy demand of this 60 w% ionic liquid is slightly lower than that of the reference solution, resulting in possible energy savings between 12 and 16%.     

Rate modeling of CO2 stripping from potassium carbonate promoted by piperazine

This work presents results from a rate-based model of strippers at normal pressure (160 kPa) and vacuum (30 kPa) in Aspen Custom Modeler^® (ACM) for the desorption of CO₂ from 5 m K⁺/2.5 m piperazine (PZ). The model solves the material, equilibrium, summation and enthalpy (MESH) equations, the heat and mass transfer rate equations, and computes the reboiler duty and equivalent work for the stripping process. Simulations were performed with IMTP #40 random packing and a temperature approach on the hot side of the cross-exchanger of 5 °C and 10 °C. A “short and fat” stripper requires 7–15% less total equivalent work than a “tall and skinny” one because of the reduced pressure drop. The vacuum and normal pressure strippers require 230 s and 115 s of liquid retention time to get an equivalent work 4% greater than the minimum work. Stripping at 30 kPa was controlled by mass transfer with reaction in the boundary layer and diffusion of reactants and products (88% resistance at the rich end and 71% resistance at the lean end). Stripping at 160 kPa was controlled by mass transfer with equilibrium reactions (84% resistance at the rich end and 74% resistance at the lean end) at 80% flood. The typical predicted energy requirement for stripping and compression to 10 MPa to achieve 90% CO₂ removal was 37 kJ/gmol CO₂. This is about 25% of the net output of a 500 MW power plant with 90% CO₂ removal.     

Modeling CO2 capture with aqueous monoethanolamine

Hilliard completed several thermodynamic models in Aspen Plus^® for modeling CO₂ removal with amine solvents, including MEA–H₂O–CO₂. This solvent was selected to make a system model for CO₂ removal by absorption/stripping. Both the absorber and the stripper used RateSep? to rigorously calculate mass transfer rates. The accuracy of the new model was assessed using a recent pilot plant run with 35 wt.% (9 m) MEA. Absorber loading and removal were predicted within 6%, and the temperature profile was approached within 5 °C. An average 3.8% difference between measured and calculated values was achieved in the stripper. A three-stage flash configuration which efficiently utilizes solar energy was developed. It reduces energy use by 6% relative to a simple stripper. Intercooling was used to reach 90% removal in the absorber at these optimized conditions.     

Novel lithium-based sorbents from fly ashes for CO2 capture at high temperatures

In this work several Li₄SiO₄-based sorbents from fly ashes for CO₂ capture at high temperatures have been developed. Three fly ash samples were collected and subjected to calcination at 950 °C in the presence of Li₂CO₃. Both pure Li₄SiO₄ and fly ash-based sorbents were characterised and tested for CO₂ sorption at different temperatures between 400 and 650 °C and adding different amounts of K₂CO₃ (0–40 mol%). To examine the sorbents performance, multiple CO₂ sorption/desorption cycles were carried out. The temperature and the presence of K₂CO₃ strongly affect the CO₂ sorption capacity for the sorbents prepared from fly ashes. When the sorption temperature increases by up to 600 °C both the CO₂ sorption capacity and the sorption rate increase significantly. Moreover when the amount of K₂CO₃ increases, the CO₂ sorption capacity also increases. At optimal experimental conditions (600 °C and 40 mol% K₂CO₃), the maximum CO₂ sorption capacity for the sorbent derived from fly ash was 107 mg CO₂/g sorbent. The Li₄SiO₄-based sorbents can maintain its original capacity during 10 cycle processes and reach the plateau of maximum capture capacity in less than 15 min, while pure Li₄SiO₄ presents a continual upward tendency for the 15 min of the capture step and attains no equilibrium capacity.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

CO2 recycling by reaction with renewably-generated hydrogen

A laboratory-scale reactor system was built and operated to demonstrate the feasibility of catalytically reacting carbon dioxide (CO₂) with renewably-generated hydrogen (H₂) to produce methane (CH₄) according to the Sabatier reaction: CO₂ + 4H₂ → CH₄ + 2H₂O. A cylindrical reaction vessel packed with a commercial methanation catalyst (Haldor Topsøe PK-7R) was used. Renewable H₂ produced by electrolysis of water (from solar- and wind-generated electricity) was fed into the reactor along with a custom blend of 2% CO₂ in N₂, meant to represent a synthetic exhaust mixture. Reaction conditions of temperature, flow rates, and gas mixing ratios were varied to determine optimum performance. The extent of reaction was monitored by real-time measurement of CO₂ and CH₄. Maximum conversion of CO₂ occurred at 300–350 °C. Approximately 60% conversion of CO₂ was realized at a space velocity of about 10,000 h^?1 with a molar ratio of H₂/CO₂ of 4/1. Somewhat higher total CO₂ conversion was possible by increasing the H₂/CO₂ ratio, but the most efficient use of available H₂ occurs at a lower H₂/CO₂ ratio.     

Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

Chilled ammonia process for CO2 capture

The chilled ammonia process absorbs the CO₂ at low temperature (2–10 °C). The heat of absorption of carbon dioxide by ammonia is significantly lower than for amines. In addition, degradation problems can be avoided and a high carbon dioxide capacity is achieved. Hence, this process shows good perspectives for decreasing the heat requirement. However, a scientific understanding of the processes is required. The thermodynamic properties of the NH₃–CO₂–H₂O system were described using the extended UNIQUAC electrolyte model developed by Thomsen and Rasmussen in a temperature range from 0 to 110 °C and pressure up to 100 bars. The results show that solid phases consisting of ammonium carbonate and bicarbonate are formed in the absorber. The heat requirements in the absorber and in the desorber have been studied. The enthalpy calculations show that a heat requirement for the desorber lower than 2 GJ/ton CO₂ can be reached.     

Heat of absorption of CO2 in aqueous ammonia and ammonium carbonate/carbamate solutions

A reaction calorimeter was used to determine the enthalpies of absorption of CO₂ in aqueous ammonia and in aqueous solutions of ammonium carbonate at temperatures of 35–80 °C. The heat of absorption of CO₂ with 2.5 wt% aqueous ammonia solution was found to be about 70 kJ/mol CO₂, which is lower than that with MEA (around 85 kJ/mol) at 35 and 40 °C. The value decreases with increased loading, but not to as low a value as expected by the carbonate–bicarbonate reaction (26.88 kJ/mol). The enthalpy of absorption of CO₂ in aqueous ammonia at 60 and 80 °C decreases with loadings at first, then increases between 0.2 mol CO₂/mol NH₃ and 0.6 mol CO₂/mol NH₃, and then decreases again. The behavior of the heat of absorption of CO₂ in 10 wt% ammonium carbonate solution was found to be the same as that of aqueous ammonia at loadings above 0.6 mol CO₂/mol NH₃. The heat of absorption increases with increasing temperature. The heats of absorption are directly related to the extent of the various reactions with CO₂ and can be assessed from the species variation in the liquid phase.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Constraints on the in situ density of CO2 within the Utsira formation from time-lapse seafloor gravity measurements

At Sleipner, CO₂ is being separated from natural gas and injected into an underground saline aquifer for environmental purposes. Uncertainty in the aquifer temperature leads to uncertainty in the in situ density of CO₂. In this study, gravity measurements were made over the injection site in 2002 and 2005 on top of 30 concrete benchmarks on the seafloor in order to constrain the in situ CO₂ density. The gravity measurements have a repeatability of 4.3 μGal for 2003 and 3.5 μGal for 2005. The resulting time-lapse uncertainty is 5.3 μGal. Unexpected benchmark motions due to local sediment scouring contribute to the uncertainty. Forward gravity models are calculated based on both 3D seismic data and reservoir simulation models. The time-lapse gravity observations best fit a high temperature forward model based on the time-lapse 3D seismics, suggesting that the average in situ CO₂ density is about to 530 kg/m³. Uncertainty in determining the average density is estimated to be ±65 kg/m³ (95% confidence), however, this does not include uncertainties in the modeling. Additional seismic surveys and future gravity measurements will put better constraints on the CO₂ density and continue to map out the CO₂ flow.     

Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

Amine volatility in CO2 capture

Amine volatility is a key screening criterion for amines to be used in CO₂ capture. Excessive volatility may result in significant economic losses and environmental impact. It also dictates the capital cost of the water wash. This paper reports measured amine volatility in 7 m MEA (monoethanolamine), 8 m PZ (piperazine), 7 m MDEA (n-methyldiethanolamine)/2 m PZ (piperazine), 12 m EDA (ethylenediamine), and 5 m AMP (2-amino-2-methyl-1-propanol) at 40–60 °C with lean and rich loadings giving CO₂ partial pressures of 0.5 and 5 kPa at 40 °C. The amine concentrations were chosen to maximize CO₂ capture capacity at acceptable viscosity. At the lean loading condition (where volatility is of greatest interest), the amines are ranked in order of increasing volatility: 7 m MDEA/2 m PZ (6/2 ppm), 8 m PZ (8 ppm), 12 m EDA (9 ppm), 7 m MEA (31 ppm), and 5 m AMP (112 ppm). The apparent amine partial molar excess enthalpies in these systems were estimated to range from ～10 to 87 kJ/mol of amine.     

Gas conditioning—The interface between CO2 capture and transport

Gas conditioning is commonly referred to as the required processing for a produced natural gas to achieve transport and sales specifications. In this paper, gas conditioning as the processing required in the interface between CO₂ capture and transport is studied for nine different natural gas fired power plant concepts and three different CO₂ transport processes. Conditioning processes for both pipeline and ship transport are described and an enhanced process for volatile removal is developed. The energy requirement for the conditioning processes is normally between 90 and 120 kWh/tonne CO₂; however, this depends on the pressure and composition of the captured CO₂-rich stream. The loss of CO₂ in the water purge is small for most capture processes. The waste streams from the gas conditioning processes can contain large amounts of CO₂ and should therefore be further processed or reintroduced at an appropriate point upstream in the capture or gas conditioning process if possible. The integration benefit may vary depending on the composition of the CO₂-rich stream. It could be particularly interesting for processes with “innovative reactors” (membranes, sorbents, chemical looping) to integrate CO₂ capture and gas conditioning.     

Techno-economic evaluation of biogas upgrading process using CO2 facilitated transport membrane

The biogas upgrading by membrane separation process using a highly efficient CO₂-selective polyvinylamine/polyvinylalcohol (PVAm/PVA) blend membrane was investigated by experimental study and simulation with respect to process design, operation optimization and economic evaluation. This blend membrane takes advantages of the unique CO₂ facilitated transport from PVAm and the robust mechanical properties from PVA, exhibits both high CO₂/CH₄ separation efficiency and very good stability. CO₂ transports through the water swollen membrane matrix in the form of bicarbonate. CO₂/CH₄ selectivity up to 40 and CO₂ permeance up to 0.55 m³(STP)/m² h bar at 2 bar were documented in lab with synthesized biogas (35% CO₂ and 65% CH₄). Membrane performances at varying feed pressures were recorded and used as the simulation basis in this work. The process simulation of an on-farm scale biogas upgrading plant (1000 Nm³/h) was conducted. Processes with four different membrane module configurations with or without recycle were evaluated technically and economically, and the 2-stage in cascade with recycle configuration was proven optimal among the four processes. The sensitivity of the process to various operation parameters was analyzed and the operation conditions were optimized.     

Carbonic anhydrase-facilitated CO2 absorption with polyacrylamide buffering bead capture

A novel CO₂ separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO₂ absorption after which hydrated CO₂ reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO₂-loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO₂-bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO₂-bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO₂-bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO₂-bearing capacity of PABB was 1.37 mol of CO₂ per kg dry bead. TGA was also used to assess the regenerability of CO₂-loaded PABB. Preliminary results suggest that CO₂ is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO₂ dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed.     

Capture of carbon dioxide from flue or fuel gas mixtures by clathrate crystallization in a silica gel column

A column of silica gel was employed to contact water with flue gas (CO₂/N₂) mixture to assess if CO₂ can be separated by hydrate crystallization. Three different silica gels were used. One with a pore size of 30 nm (particle size 40–75 μm) and two with a pore size of 100 nm and particle sizes of 40–75 and 75–200 μm respectively. The observed trends indicate that larger pores and particle size increase the gas consumption, CO₂ recovery, separation factor and water conversion to hydrate. Thus, the gel (gel #3) with the larger particle size and larger pore size was chosen to carry out experiments with concentrated CO₂ mixtures and for experiments in the presence of tetrahydrofuran (THF), which itself is a hydrate forming substance. Addition of THF reduces the operating pressure in the crystallizer but it also reduces the gas uptake. Gel #3 was also used in experiments with a fuel gas (CO₂/H₂) mixture in order to recover CO₂ and H₂. It was found that the gel column performs as well as a stirred reactor in separating the gas components from both flue gas and fuel gas mixtures. However, the crystallization rate and hydrate yield are considerably enhanced in the former. Finally the need for stirring is eliminated with the gel column which is enormously beneficial economically.