Experimental assessment of brine and/or CO2 leakage through well cements at reservoir conditions

Two sets of experiments on typical Class G well cement were carried out in the laboratory to understand better the potential processes involved in well leakage in the presence of CO₂. In the first set, good-quality cement samples of permeability in the order of 0.1 μD (10^?19 m²) were subjected to 90 days of flow through with CO₂-saturated brine at conditions of pressure, temperature and water salinity characteristic of a typical geological sequestration zone. Cement permeability dropped rapidly at the beginning of the experiment and remained almost constant thereafter, most likely mainly as a result of CO₂ exsolution from the saturated brine due to the pressure drop along the flow path which led to multi-phase flow, relative-permeability effects and the observed reduction in permeability. These processes are identical to those which would occur in the field as well if the cement sheath in the wellbore annulus is of good quality. The second set of experiments, carried out also at in situ conditions and using ethane rather than CO₂ to eliminate any possible geochemical effects, assessed the effect of annular spaces between wellbore casing and cement, and of radial cracks in cement on the effective permeability of the casing-cement assemblage. The results show that, if both the cement and the bond are of good quality, the effective permeability of the assemblage is extremely low (in the order of 1 nD, or 10^?21 m²). The presence of an annular gap and/or cracks in the order of 0.01–0.3 mm in aperture leads to a significant increase in effective permeability, which reaches values in the range of 0.1–1 mD (10^?15 m²). The results of both sets of experiments suggest that good cement and good bonding with casing and the surrounding rock will likely constitute a good and reliable barrier to the upward flow of CO₂ and/or CO₂-saturated brine. The presence of mechanical defects such as gaps in bonding between the casing or the formation, or cracks in the cement annulus itself, leads to flow paths with significant effective permeability. This indicates that the external and internal interfaces of cements in wells would most probably constitute the main flow pathways for fluids leakage in wellbores, including both gaseous/supercritical phase CO₂ and CO₂-saturated brine.     

Experimental investigation of wellbore integrity and CO2–brine flow along the casing–cement microannulus

Wellbore integrity is one of the key performance criteria in the geological storage of CO₂. It is significant in any proposed storage site but may be critical to the suitability of depleted oil and gas reservoirs that may have 10’s to 1000’s of abandoned wells. Much previous work has focused on Portland cement which is the primary material used to seal wellbore systems. This work has emphasized the potential dissolution of Portland cement. However, an increasing number of field studies (e.g., Carey et al., 2007), experimental studies (e.g., Kutchko et al., 2006) and theoretical considerations indicate that the most significant leakage mechanism is likely to be flow of CO₂ along the casing–cement microannulus, cement–cement fractures, or the cement–caprock interface.In this study, we investigate the casing–cement microannulus through core-flood experiments. The experiments were conducted on a synthetic wellbore system consisting of a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing that had grooves to accommodate fluid flow. The experiments were conducted at 40 $°$ C and 14 MPa pore pressure for 394 h. During the experiment, 6.2 l of a 50:50 mixture of supercritical CO₂ and 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement–casing wellbore system. Approximately 59,000 pore volumes of fluid moved through the casing–cement grooves. Scanning electron microscopy revealed that the CO₂–brine mixture impacted both the casing and the cement. The Portland cement was carbonated to depths of 50–250 $\mu$m by a diffusion-dominated process. There was very little evidence for mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of mixed calcium and iron carbonate that lined the channels and in one case almost completely filled a channel. The depth of steel corroded was estimated at 25– $30\mu$m and was similar in value to results obtained with a simplified corrosion model.The experimental results were applied to field observations of carbonated wellbore cement by Carey et al. (2007) and Crow et al. (2009) to show that carbonation of the field samples was not accompanied by significant CO₂–brine flow at the casing–cement interface. The sensitivity of standard-grade steel casing to corrosion suggests that relatively straight-forward wireline logging of external casing corrosion could be used as a useful indicator of flow behind casing. These experiments also reinforce other studies that indicate rates of Portland cement deterioration are slow, even in the high-flux CO₂–brine experiments reported here.     

Analysis and performance of oil well cement with 30 years of CO2 exposure from the SACROC Unit,West Texas,USA

A core sample including casing, cement, and shale caprock was obtained from a 30-year old CO₂-flooding operation at the SACROC Unit, located in West Texas. The core was investigated as part of a program to evaluate the integrity of Portland-cement based wellbore systems in CO₂-sequestration environments. The recovered cement had air permeabilities in the tenth of a milliDarcy range and thus retained its capacity to prevent significant flow of CO₂. There was evidence, however, for CO₂ migration along both the casing–cement and cement–shale interfaces. A 0.1–0.3 cm thick carbonate precipitate occurs adjacent to the casing. The CO₂ producing this deposit may have traveled up the casing wall or may have infiltrated through the casing threads or points of corrosion. The cement in contact with the shale (0.1–1 cm thick) was heavily carbonated to an assemblage of calcite, aragonite, vaterite, and amorphous alumino-silica residue and was transformed to a distinctive orange color. The CO₂ causing this reaction originated by migration along the cement–shale interface where the presence of shale fragments (filter cake) may have provided a fluid pathway. The integrity of the casing–cement and cement–shale interfaces appears to be the most important issue in the performance of wellbore systems in a CO₂ sequestration reservoir.     

CO2SINK—From site characterisation and risk assessment to monitoring and verification: One year of operational experience with the field laboratory for CO2 storage at Ketzin, Germany

The CO₂SINK pilot project at Ketzin is aimed at a better understanding of geological CO₂ storage operation in a saline aquifer. The reservoir consists of fluvial deposits with average permeability ranging between 50 and 100 mDarcy. The main focus of CO₂SINK is developing and testing of monitoring and verification technologies. All wells, one for injection and two for observation, are equipped with smart casings (sensors behind casing, facing the rocks) containing a Distributed Temperature Sensing (DTS) and electrodes for Electrical Resistivity Tomography (ERT). The in-hole Gas Membrane Sensors (GMS) observed the arrival of tracers and CO₂ with high temporal resolution. Geophysical monitoring includes Moving Source Profiling (MSP), Vertical Seismic Profiling (VSP), crosshole, star and 4-D seismic experiments. Numerical models are benchmarked via the monitoring results indicating a sufficient match between observation and prediction, at least for the arrival of CO₂ at the first observation well. Downhole samples of brine showed changes in the fluid composition and biocenosis. First monitoring results indicate anisotropic flow of CO₂ coinciding with the “on-time” arrival of CO₂ at observation well one (Ktzi 200) and the later arrival at observation well two (Ktzi 202). A risk assessment was performed prior to the start of injection. After one year of operations about 18,000 t of CO₂ were injected safely.     

Assessment of basin-scale hydrologic impacts of CO2 sequestration,Illinois basin

Idealized, basin-scale sharp-interface models of CO₂ injection were constructed for the Illinois basin. Porosity and permeability were decreased with depth within the Mount Simon Formation. Eau Claire confining unit porosity and permeability were kept fixed. We used 726 injection wells located near 42 power plants to deliver 80 million metric tons of CO₂/year. After 100 years of continuous injection, deviatoric fluid pressures varied between 5.6 and 18 MPa across central and southern part of the Illinois basin. Maximum deviatoric pressure reached about 50% of lithostatic levels to the south. The pressure disturbance (>0.03 MPa) propagated 10–25 km away from the injection wells resulting in significant well–well pressure interference. These findings are consistent with single-phase analytical solutions of injection. The radial footprint of the CO₂ plume at each well was only 0.5–2 km after 100 years of injection. Net lateral brine displacement was insignificant due to increasing radial distance from injection well and leakage across the Eau Claire confining unit. On geologic time scales CO₂ would migrate northward at a rate of about 6 m/1000 years. Because of paleo-seismic events in this region (M5.5–M7.5), care should be taken to avoid high pore pressures in the southern Illinois basin.     

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.     

Hydraulic characterisation of the Stuttgart formation at the pilot test site for CO2 storage, Ketzin, Germany

The paper presents an approach for the interpretation of hydraulic tests of a CO₂ storage reservoir. The sandstone reservoir is characterised by a fluviatile channel structure embedded in a low-permeability matrix. Pumping tests were carried out in three wells, with simultaneous pressure monitoring in each well.The hydraulic parameters (permeability and storativity) and the boundary configurations were calibrated using three different approaches: (i) parameter calibration and type curve interpretation for single-hole tests, (ii) calibration of the entire build-up phase for cross-hole tests, and (iii) calibration of the initial pressure response for cross-hole pumping tests. In addition, the arrival time of the pressure response was determined and provides additional information about the pathways of hydraulic connection.The measured pumping test permeabilities of the formation were much lower than those measured on the cores, which is very unusual. The pumping test permeabilities are mainly between 50 mD and 100 mD (millidarcy), while core samples show a mean aquifer permeability of 500–1100 mD. Based on this it was concluded that some kind of continuous low-permeability structure exists, which was supported by core material. Three possible aquifer configurations were considered. The first and second were derived from traditional pumping test analysis and were conceptualised using flow boundaries. Each of the analyses provides a different result. A method was developed in which these differences were resolved by interpreting the pressure response with respect to its spatial and temporal sensitivity. This solution lead to a third configuration which was mainly based on spatially-variable permeabilities. Taking into account the pumping test results, the geological background and the behaviour of injected CO₂, we consider only the third configuration to be realistic. The results are in good agreement with modelled CO₂ arrival times and pressure history.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.     

CCS scenarios optimization by spatial multi-criteria analysis: Application to multiple source sink matching in Hebei province

A method, based on spatial analysis of the different criteria to be taken into consideration for building scenarios of CO₂ capture and storage (CCS), has been developed and applied to real case studies in the Hebei province. Totally 88 point sources (42 from power sector, 9 from iron and steel, 18 from cement, 16 from ammonia, and 3 from oil refinery) are estimated and their total emission amounts to 231.7 MtCO₂/year with power, iron and steel, cement, ammonia and oil refinery sharing 59.13%, 25.03%, 11.44%, 3.5%, and 0.91%, respectively. Storage opportunities can be found in Hebei province, characterised by a strong tectonic subsidence during the Tertiary, with several kilometres of accumulated clastic sediments. Carbon storage potential for 25 hydrocarbon fields selected from the Huabei complex is estimated as 215 MtCO₂ with optimistic assumption that all recovered hydrocarbon could be replaced by an equivalent volume of CO₂ at reservoir conditions. Storage potential for aquifers in the Miocene Guantao formation is estimated as 747 MtCO₂ if closed aquifer assumed or 371 MtCO₂ if open aquifer and single highly permeable horizon assumed. Due to poor knowledge on deep hydrogeology and to pressure increase in aquifer, injecting very high rates requested by the major CO₂ sources (>10 MtCO₂/year) is the main challenge, therefore piezometry and discharge must be carefully controlled. A source sink matching model using ArcGIS software is designed to find the least-cost pathway and to estimate transport route and cost accounting for the additional costs of pipeline construction due to landform and land use. Source sink matching results show that only 15–25% of the emissions estimated for the 88 sources can be sequestrated into the hydrocarbon fields and the aquifers if assuming sinks should be able to accommodate at least 15 years of the emissions of a given source.     

Biofilm enhanced geologic sequestration of supercritical CO2

In order to develop subsurface CO₂ storage as a viable engineered mechanism to reduce the emission of CO₂ into the atmosphere, any potential leakage of injected supercritical CO₂ (SC-CO₂) from the deep subsurface to the atmosphere must be reduced. Here, we investigate the utility of biofilms, which are microorganism assemblages firmly attached to a surface, as a means of reducing the permeability of deep subsurface porous geological matrices under high pressure and in the presence of SC-CO₂, using a unique high pressure (8.9 MPa), moderate temperature (32 °C) flow reactor containing 40 millidarcy Berea sandstone cores. The flow reactor containing the sandstone core was inoculated with the biofilm forming organism Shewanella fridgidimarina. Electron microscopy of the rock core revealed substantial biofilm growth and accumulation under high-pressure conditions in the rock pore space which caused >95% reduction in core permeability. Permeability increased only slightly in response to SC-CO₂ challenges of up to 71 h and starvation for up to 363 h in length. Viable population assays of microorganisms in the effluent indicated survival of the cells following SC-CO₂ challenges and starvation, although S. fridgidimarina was succeeded by Bacillus mojavensis and Citrobacter sp. which were native in the core. These observations suggest that engineered biofilm barriers may be used to enhance the geologic sequestration of atmospheric CO₂.     

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.     

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.     

Analytical solution for Joule–Thomson cooling during CO2 geo-sequestration in depleted oil and gas reservoirs

Mathematical tools are needed to screen out sites where Joule–Thomson cooling is a prohibitive factor for CO₂ geo-sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO₂ injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kg s^?1 (0.1 MT yr^?1) into moderately warm (>40 °C) and permeable formations (>10^?14 m² (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as 2 MPa (290 psi).     

Geoelectrical methods for monitoring geological CO2 storage: First results from cross-hole and surface–downhole measurements from the CO2SINK test site at Ketzin (Germany)

The feasibility of monitoring CO₂ migration in a saline aquifer at a depth of about 650 m with cross-hole and surface–downhole electrical resistivity tomography (ERT) is investigated at the CO₂SINK test site close to Ketzin (Germany). The permanent vertical electrical resistivity array (VERA) consists of 45 electrodes (15 in the injection well Ktzi201 and 15 in each of the two observation wells Ktzi200 and Ktzi202), successfully placed on the electrically insulated casings, in the depth range of about 590–740 m with a spacing of about 10 m. The three Ketzin wells are arranged as perpendicular triangle with distances of 50 and 100 m.First synthetic modelling studies indicate an increase of the electrical resistivity of about 200% caused by CO₂ injection, corresponding to a bulk CO₂ saturation of 50%, which is in good agreement with laboratory studies. Finite difference inversion of field data delivers three-dimensional resistivity distributions between the wells which are consistent with the reservoir modelling studies.To increase the limited observation area provided by the cross-hole measurements, additional surface–downhole measurements were deployed. A main CO₂ migration in SE–NW direction is deduced from surface to downhole resistivity experiments.The first cross-hole time-lapse results show that the resolution and the coverage of the electrode array in the Ketzin setting are sufficient to resolve the expected resistivity changes on the characteristic length scale of the electrode array. Significant resistivity changes could be measured, however, detailed information on the CO₂ plume could not be resolved yet by VERA under the existing geological circumstances.     

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.     

Hydrate formation during CO2 transport: Predicting water content in the fluid phase in equilibrium with the CO2-hydrate

In order to evaluate the risk of hydrate formation in CO₂ transport one has to be able to predict the water content in the fluid phase in equilibrium with the CO₂-hydrate. A literature review has identified some knowledge gaps, for example, there are no results available at temperatures lower than 243.15 K (?30 °C); and none of the models found in literature predicts the water content with high accuracy. A model based on equality of water fugacity in fluid and hydrate phase is presented here and used for the predictions of water content in equilibrium with hydrates. Although this model gives better accuracy in the overall temperature and pressure ranges of measurements than the models found in the literature, it is not accurate enough to satisfy the requirements of CO₂ transport. The simulation results also show that it is possible to form hydrate at low water content, such as x_w = 50 vppm, if temperature is low enough. In order to verify the results and improve the model accuracy further, more experimental data in a larger temperature and pressure region are required.     

Modelling of CO2 arrival time at Ketzin – Part I

The injection of CO₂ at the Ketzin storage site and the chemical detection of its arrival in the observation well allowed testing of different numerical simulation codes. ECLIPSE 100 (E100, black-oil simulator), ECLIPSE 300 (E300, compositional CO₂STORE) and MUFTE-UG were used for predictive modelling applying a constant injection rate of 1 kg s^?1 CO₂ and for a history match applying the actual variable injection rate which ranged from 0 to 0.7 kg s^?1 and averaged 0.23 kg s^?1. The geological model applied, is based on all available geophysical and geological information and has been the same for all programs.The results of the constant injection regime show a good agreement among the programs with a discrepancy of 21–33% for the CO₂ arrival times. However, it is determined from the comparison of the cumulative mass of CO₂ at the time of CO₂ arrival that the injection regime is an important factor for the accurate prediction of CO₂ migration within a saline aquifer. Comparing the actual variable injection regime with the simulations applying a constant injection rate the results are relatively inaccurate.Regarding the actual variable injection regime, which was evaluated using all three simulators, the computational results show a good agreement with the data actually measured at the first observation well. Here, the calculated arrival times exceeded the actual ones by 8.1% (E100), 9.2% (E300) and 17.7% (MUFTE-UG).It can be concluded that irrespective of the deviations of the simulations, due to combinations of different codes and slight differences in input parameters, all three programs are well equipped to give a reliable estimate of the arrival of CO₂. Deviations in the results mainly occur due to different input data and grid size choices done by the different modelling teams working independently of each other. Deviations of the simulations results compared to the actual CO₂ arrival time result from uncertainties in the implementation of the geological model, which was set up based on well log data and analogue studies.     

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.     

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 capture from power plants: Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO₂ emission is increasing, the cost of the CO₂ capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO₂ capture from 600 MW_e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO₂-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO₂ capture process based on absorption/desorption with MEA solutions was performed.Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO₂ avoided cost of € 33 tonne⁻¹ CO₂ was found for a lean solvent loading of 0.3 mol CO₂/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO₂ of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh⁻¹ increase in the cost of electricity, compared to € 31.4 MWh⁻¹ for the power plant without capture.