[1] We report the results of an experimental investigation into the multiphase flow properties of CO 2 and water in four distinct sandstone rocks: a Berea sandstone and three reservoir rocks from formations into which CO 2 injection is either currently taking place or is planned. Drainage relative permeability and residual gas saturations were measured at 50 C and 9 MPa pore pressure using the steady state method in a horizontal core flooding apparatus with fluid distributions observed using x-ray computed tomography. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample. Relative permeability in the four samples is consistent with general characteristics of drainage in strongly water-wet rocks. Measurements in the Berea sample are also consistent with past measurements in Berea sandstones using both CO 2 /brine and oil/water fluid systems. Maximum observed saturations and permeabilities are limited by the capillary pressure that can be achieved in the experiment and do not represent endpoint values. It is likely that maximum saturations observed in other studies are limited in the same way and there is no indication that low endpoint relative permeabilities are a characteristic of the CO 2 /water system. Residual trapping in three of the rocks is consistent with trapping in strongly water-wet systems, and the results from the Berea sample are again consistent with observations in past studies. This confirms that residual trapping can play a major role in the immobilization of CO 2 injected into the subsurface. In the Mt. Simon sandstone, a nonmonotonic relationship between initial and residual CO 2 saturations is indicative of a rock that is mixed or intermediate wet, and further investigations should be performed to establish the wetting properties of illite-rich rocks. The combined results suggest that the petrophysical properties of the multiphase flow of CO 2 /water through siliciclastic rocks is for the most part typical of a strongly water-wet system and that analog fluids and conditions may be used to characterize these properties. Further investigation is required to identify the wetting properties of illite-rich rocks during imbibition processes.

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Gases like CO 2 and CH 4 are able to adsorb on the coal surface, but also to dissolve into its structure causing the coal to swell. In this work, the binary adsorption of CO 2 and CH 4 on a dry coal (Sulcis Coal Province, Italy) and its swelling behavior are investigated. The competitive adsorption measurements are performed at 45°C and up to 190 bar for pure CO 2 , CH 4 and four mixtures of molar feed compositions of 20.0, 40.0, 60.0 and 80.0% CO 2 using a gravimetric-chromatographic technique. The results show that carbon dioxide adsorbs more favorably than methane leading to an enrichment of the fluid phase in CH 4 . Coal swelling is determined using a high-pressure view cell, by exposing a coal disc to CO 2 , CH 4 and He at 45 and 60°C and up to 140 bar. For CO 2 and CH 4 a maximum swelling of about 4 and 2% is found, whereas He shows negligible swelling. The presented adsorption and swelling data are then discussed in terms of fundamental, thermodynamic aspects of adsorption and properties which are crucial for an ECBM operation, i.e. the CO 2 storage capacity and the dynamics of the replacement of CH 4 by CO 2 .

[1] Capillary pressure and relative permeability drainage curves are simultaneously measured on a single Berea Sandstone core by using three different fluid pairs, namely gCO 2 /water, gN 2 /water and scCO 2 /brine. This novel technique possesses many of the characteristics of a conventional steady-state relative permeability experiment and consists of injecting the nonwetting fluid at increasingly higher flow rates in a core that is initially saturated with the wetting phase, while observing fluid saturations with a medical x-ray CT scanner. Injection flow rates (0.5-75 mL/min) are varied so as to generate a large range of capillary pressures (up to 18 kPa), whereas fluid-pairs and experimental conditions are selected in order to move across a range interfacial tension values ( 12 ¼ 40 À 65 mN/m), while maintaining a constant viscosity ratio ( w = nw % 30). Moreover, these experiments, carried out at moderate pressures (P ¼ 2:4 MPa and T ¼ 50 C), can be compared directly with results for gas/liquid pairs reported in the literature and they set the benchmark for the experiment at a higher pressure (P ¼ 9 MPa and T ¼ 50 C), where CO 2 is in the supercritical state. Contrary to some prior investigations, from these experiments we find no evidence that the scCO 2 /brine system behaves differently than any of these other fluid pairs. At the same time, capillary pressure data show a significant (but consistent) effect of the different values for the interfacial tension. The fact that the three different fluid pairs yield the same drainage relative permeability curve is consistent with observations in the petroleum literature. Additionally, the observed end-point values for the relative permeability to the nonwetting phase (k r;nw % 0:9) and the corresponding irreducible water saturations (S w;irr % 0:35) suggest that water-wet conditions are maintained in each experiment. The reliability of the measured relative permeability curves is supported by the very good agreement with data from the literature obtained on Berea Sandstone cores and with various gas/liquid pairs. The Brooks-Corey model is used to describe the capillary pressure data and the parameters derived from these matches provide a fair prediction of the relative permeability curves. It is shown that the apparent low end-point relative permeabilities to the nonwetting phase reported in previous experimental studies are caused by the low viscosity of CO 2 relative to water, rather than by the rock heterogeneity. In fact, the former controls the level of capillary pressure that can be achieved experimentally, thus restricting the applicability of some of the conventional methods to measure relative permeability curves for gas/liquid systems.Citation: Pini, R., and S. M. Benson (2013), Simultaneous determination of capillary pressure and relative permeability curves from core-flooding experiments with various fluid pairs, Water Resour. Res., 49,[3516][3517][3518][3519][3520][3521][3522][3523][3524][3525][3526][3527][3528][3529][3530]

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A new developing field of application for pressure swing adsorption (PSA) processes is the capture of CO 2 to mitigate climate change, especially the separation of CO 2 and H 2 in a pre-combustion context. In this process scheme the conditions of the feed to the separation step, namely a pressure of 3.5 to 4.5 MPa and a CO 2 fraction of around 40% are favorable for an adsorption based separation process and make PSA a promising technology. Among the commercial adsorbent materials, activated carbon is most suitable for this application. To evaluate the potential, to benchmark new materials, and for process development a sound basis of the activated carbon thermodynamic data is required, namely equilibrium adsorption isotherms of the relevant pure components and mixtures, Henry's constants and isosteric heats.In this work pure adsorption equilibria of CO 2 , H 2 and N 2 on commercial activated carbon (AP3-60 from Chemviron, Germany) are measured using a Rubotherm Magnetic Suspension Balance (MSB) (Bochum, Germany) in a wide temperature and pressure range. The data is used to fit the temperature dependent parameters of Langmuir and Sips (Langmuir-Freundlich) isotherms and to determine the Henry's constants as well as isosteric heats. Based on this evaluation different methods to evaluate the data are compared and discussed. With the pure isotherm parameters of the Sips isotherm binary adsorption is predicted using an empirical binary Sips equation and ideal adsorbed solution theory (IAST). The results are compared to binary measurements in the same MSB applying a gravimetricchromatographic method. Notation a parameter for temperature dependent description of n ∞ i [mmol/g] A specific surface of the adsorbent (Gibbs Adsorption isotherm) [m 2 /kg] A parameter for temperature dependent description of k i [1/MPa] b parameter for temperature dependent description of n ∞ i [J/mol] B parameter for temperature dependent description of k i [J/mol] c exponent in Sips isotherm [-] C parameter for temperature dependent description of H i [mmol/g/MPa] D parameter for temperature dependent description of H i [J/mol] E squared error from isotherm fitting [(mmol/g) 2 ] g weighting factor (final) [-] H Henry's constant [mmol/g/MPa] H heat of adsorption [kJ/mol] k isotherm equilibrium constant [1/MPa] m mass [g] M 1 weight at measuring point 1 [g] M 0 1 weight at measuring point 1 under vacuum [g] M molar mass [g/mol] n molar adsorption per unit mass of adsorbent [mmol/g] N number of experimental data points at one temperature (one component) [-] 50 Adsorption (2012) 18:49-65 p pressure [MPa] r weighting factor [-] R ideal gas constant [J/mol/K] S selectivity [-] t weighting factor [-] T Temperature [K] V Volume [cm 3 ] V 0 Volume of lifted metal parts and adsorbent [cm 3 ] V void Void volume of the adsorption system [cm 3 ] V 2 second virial coefficient for isotherm description [g/mmol] V 3 third virial coefficient for isotherm description [g 2 /mmol 2 ] w mass fraction [-] y mole fraction in fluid [-] z mole fraction in adsorbed ph...

[1] The storage of CO 2 in deep subsurface porous rocks is being developed worldwide for the mitigation of emission from large industrial sources such as power plants and steel manufacturing. A main concern of this technology is in ensuring that the upwardly buoyant CO 2 does not migrate to the surface. Simulation studies suggest that substantial amounts of CO 2 can be trapped within permeable sections of a reservoir by capillary forces and intra-reservoir heterogenities, but there is little experimental observation of these phenomena. We report the results of CO 2 core flooding experiments at high pressure and temperature performed to investigate the impact of natural capillary heterogeneity in a sandstone rock on CO 2 saturation buildup and trapping. CO 2 and water were injected through a Mt. Simon sandstone core at 9 MPa pore pressure and 50°C. The core had two regions of distinct capillarity: An upstream 10 cm long region of the core consisted of a relatively high permeability and homogenous sand. A downstream 3 cm long region of the core consisted of a low permeability region characterized by significant crossbedding and a high capillary entry pressure for CO 2 . During a drainage process of CO 2 displacing water, CO 2 builds up upstream of the capillary barrier. Once in place, CO 2 on the upstream side of the barrier cannot be displaced during 100% water flooding leading to trapped saturations that are a factor 2-5 times higher than what would be expected from residual trapping alone.

High-resolution x-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature, and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment under water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of 80 • with a standard deviation of 17 •. We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary pressure and with an almost fixed area, removing most of the oil.