An experimental method has been developed to determine the wettability, i.e., the contact angle, of a reservoir brine−reservoir rock system with dissolution of CO2 at high pressures and elevated temperatures by using the axisymmetric drop shape analysis (ADSA) technique for the sessile drop case. Prior to the experiment, a rock slide is horizontally placed in a specially designed rock slide holder in a see-through windowed high-pressure cell, which is subsequently filled with CO2 at a prespecified pressure and a constant temperature. Then, a reservoir brine sample is introduced by using a syringe delivery system to form a sessile brine drop on the rock slide inside the pressure cell. The sequential digital images of the dynamic sessile brine drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic contact angles at different times. It is found that the dynamic contact angle between the reservoir brine and the reservoir rock remains almost constant at a given pressure and a constant temperature, though CO2 is gradually dissolved into the sessile brine drop which is eventually saturated with CO2. It is also found that the equilibrium contact angle increases as the pressure increases, whereas it decreases as the temperature increases. Such wettability alteration may significantly affect the storage capacity when CO2 is injected into a saline aquifer or a depleted oil reservoir at high pressures.

In this paper, an experimental technique has been developed to study the interfacial interactions of the reservoir brine-CO 2 system at high pressures and elevated temperatures. Using the axisymmetric drop shape analysis (ADSA) for the pendant drop case, this new technique makes it possible to determine the interfacial tension (IFT) and visualize the interfacial interactions between the reservoir brine and CO 2 under practical reservoir conditions. More specifically, the dynamic IFT between the reservoir brine and CO 2 is measured as a function of pressure at two different temperatures. It is found that the dynamic IFT gradually reduces to a constant value, which is termed as the equilibrium IFT. The equilibrium IFT decreases as the pressure increases, whereas the same parameter increases as the temperature increases. The major interfacial interactions observed in this study include interface disappearance, the swelling effect, the shrinking effect, and wettability alteration. At an elevated temperature (T ) 58 °C), the pendant brine drop cannot be observed in the CO 2 phase at a pressure of P g 12.238 MPa. It is also found that CO 2 solubility in the brine phase, which is measured using the PVT system, approaches its maximum value under the same conditions. Further increases in pressure do not noticeably increase the CO 2 solubility in the brine phase. The brine swelling effect is observed at all the pressures and temperatures tested, whereas the brine shrinking effect occurs only at high pressures and a lower temperature (T ) 27 °C). In addition, the wettability of the reservoir brine-CO 2 system changes from the hydrophilic case to the hydrophobic case when the CO 2 changes from the gas phase to the liquid phase.

Summary In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with the addition of either solvent C3H8 or solvent n-C4H10. Experimentally, pressure/volume/temperature (PVT) tests are conducted to measure the saturation pressure, swelling factor, and viscosity of the C3H8/heavy-oil system, the C3H8/CO2/heavy-oil system, and the n-C4H10/CO2/heavy-oil system, respectively, in the overall temperature range of 280.45 to 391.55 K. It has been found that an increased swelling effect of heavy oil is obtained by adding the gas solvent C3H8 or n-C4H10 into the CO2 stream. An enhanced viscosity reduction of the CO2/heavy-oil system is also achieved in the presence of either C3H8 or n-C4H10. The enhanced swelling effect and viscosity reduction caused by adding either C3H8 or n-C4H10 into the CO2 stream are particularly favorable for achieving a higher heavy-oil recovery compared with pure-CO2 processes. Theoretically, three binary-interaction-parameter (BIP) correlations in the Peng-Robinson (PR) equation of state (EOS) (PR-EOS) method have been proposed for respectively characterizing CO2/heavy-oil binaries, C3H8/heavy-oil binaries, and n-C4H10/heavy-oil binaries by treating each oil sample as a single pseudocomponent with its molecular weight (MW) and specific gravity (SG). The BIP correlations (together with the PR-EOS) can be used to predict the saturation pressures and swelling factors of the C3H8/CO2/heavy-oil system and the n-C4H10/CO2/heavy-oil system with a generally good accuracy.

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An experimental method has been developed to determine the wettability, i.e., the contact angle, of the crude oil−reservoir brine−reservoir rock system with dissolution of CO2 at high pressures and elevated temperatures, using the axisymmetric drop shape analysis (ADSA) technique for the sessile drop case. In the experiment, a see-through windowed high-pressure cell is prefilled with reservoir brine to submerge the reservoir rock. Subsequently, CO2 is slowly injected through the brine phase to pressurize the system to a prespecified pressure at a constant temperature. After the CO2−reservoir brine system reaches the equilibrium state, a crude oil sample is introduced by using a specially designed syringe delivery system to form a sessile oil drop on the reservoir rock inside the pressure cell. The sequential images of the dynamic sessile oil drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic contact angles at different times. It is found that the dynamic contact angle between the crude oil and the reservoir rock in the presence of CO2-saturated reservoir brine remains almost constant at a given pressure and a constant temperature, though CO2 is gradually dissolved into the sessile oil drop until the latter is completely saturated with the former. It is also found that the equilibrium contact angle increases as the pressure increases, whereas it decreases as the temperature increases. In comparison with the equilibrium contact angle data for the crude oil−reservoir brine−reservoir rock system without any dissolution of CO2, the equilibrium contact angles of the crude oil−reservoir brine−reservoir rock system with dissolution of CO2 are smaller at T = 27 °C but larger at T = 58 °C. Such wettability alteration will significantly affect oil recovery and subsequent storage when CO2 is injected into an oil reservoir at high pressures.

The NMR relaxometry measurements have been designed and applied to quantitatively determine residual oil distribution during waterflooding in tight oil formations. A tight core sample is first saturated with water to measure its NMR transverse relaxation time (T 2 ) spectrum. NMR T 2 spectrum is then measured for the core sample after it has been displaced with the fluorinated oil. Subsequently, the core sample is displaced with water until residual oil saturation is achieved, and the NMR T 2 spectrum is measured again at the end of the displacement. Subsequently, the constant-rate mercury injection method is used to experimentally measure the size of the pore and throat in the core sample. The residual oil saturation is determined as a function of pore size by comparing the difference between the first and last NMR T 2 spectrum. It is found from four core samples with permeability of 0.04−1.70 mD that the average pore size is in a range of 129−145 μm, and the pore throat has a radius of 0.17− 0.89 μm. The original oil saturation is found to be 76−83%, whereas the oil recovery factor is 36−62%; 4−27% of the original oil is distributed in pores larger than 100 μm, 50−54% in pores from 10 to 100 μm, and 21−46% in pores and throats smaller than 10 μm. Residual oil saturation is 1−2% in pores larger than 100 μm, 29−64% in pores from 10 to 100 μm, and 34−69% in pores and throats smaller than 10 μm.

A novel methodology was developed to determine the moleculardiffusion coefficient for each component of the solvent/CO 2 mixture in heavy oil under reservoir conditions on the basis of the pressure-decay theory. Experimentally, molecular-diffusion tests for the solvent/CO 2 /heavy-oil systems (i.e., pure-CO 2 /heavy-oil system, C 3 H 8 /CO 2 /heavy-oil system, and n-C 4 H 10 /CO 2 /heavy-oil system) are performed with a DBR pressure/volume/temperature system at constant temperature and decayed pressure. Theoretically, the Peng-Robinson equation of state combined with a 1D diffusion model is developed to describe the diffusion process of solvent/CO 2 mixture in heavy oil. The composition analysis in the beginning and the end of pressure-decay experiments for the solvent/CO 2 /heavy-oil system indicate that the gas-phase solvent fraction decreases as diffusion proceeds, whereas the gas-phase CO 2 fraction increases during the tests. One can determine the individual molecular-diffusion coefficient for each component in the mixture by minimizing the discrepancy between the measured composition change and the calculated composition change with the diffusion model. The newly developed methodology is successfully validated with the diffusion tests on the two solvent/CO 2 mixtures: C 3 H 8 /CO 2 /heavy-oil system and n-C 4 H 10 /CO 2 /heavyoil system. As for the solvent/CO 2 mixtures tested, the moleculardiffusion coefficient of solvent in heavy oil is found to be significantly larger than that of CO 2 in heavy oil. At similar test conditions, the C 3 H 8 /CO 2 /heavy-oil system ends up with a swelling factor of 1.058 after 168 hours of diffusion test, in comparison to 1.031 for the CO 2 /heavy-oil system. Experimental Materials.A heavy-oil sample is collected from the Lloydminster area in Saskatchewan, Canada. The heavy-oil sample has a molecular weight (MW) of 482 g/mol and a density of 999.7 kg/m 3 . Table 1 shows the compositional-analysis result for the heavy oil. The viscosity of the heavy-oil sample is given by (Li et al. 2013a)

Techniques have been developed to experimentally and numerically evaluate performance of CO2 huff-n-puff processes for unlocking resources from tight oil formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.27-0.83 mD are used to conduct a series of coreflooding experiments. The performance of four recovery schemes, i.e., waterflooding, immiscible CO2 huff-n-puff, near-miscible CO2 huff-n-puff, and miscible CO2 huff-n-puff processes, is evaluated with the tight core samples. The waterflooding process leads to a higher oil recovery factor in comparison with the immiscible CO2 huff-n-puff process, while both the near-miscible and miscible CO2 huff-n-puff processes result in higher recovery efficiency compared to that of waterflooding. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different recovery schemes. There exists a generally good agreement between the experimental measurements and simulated results. The tuned numerical model is then employed to optimize the injection pressure and soaking time during CO2 huff-n-puff processes. It is found that the optimum injection pressure of the CO2 huff-n-puff process can be set around the minimum miscibility pressure (MMP) between crude oil and CO2, while the soaking time can be optimized for maximizing oil recovery.