Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-Miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis, and Permeability

Abstract

Near-miscible gas injection represents a number of processes of great importance to reservoir engineers, including hydrocarbon gas injection and CO 2 flood. Very little experimental data is available in the literature on displacements involving very low interfacial tension (IFT). In this paper, we present the results of a series of two-and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for a gas/oil system at near-miscible (IFT = 0.04 mN m −1 ) conditions. Two different cores, a high-permeability (1000 mD) and a lower permeability (65 mD) core, were used in the experiments, and both water-and mixed-wet conditions were examined. The results show that, despite a very low gas/oil IFT, there is significant hysteresis between the imbibition and drainage oil and gas relative permeability (k r ) curves in the 65 mD core. Hysteresis was less for the 1000 mD core (in comparison to the 65 mD core), but it still could not be ignored. Near-miscible k r hysteresis was significant for both water-and mixed-wet systems. The presence of immobile water in the water-wet cores improved oil relative permeabilities but reduced gas relative permeabilities in both imbibition and drainage directions. As a result, oil recovery for gas injection experiments improved when the rock contained immobile water. Both oil and gas relative permeabilities reduced when the rock wettability was altered to mixed-wet from water-wet, and as a result, oil recovery by gas injection in the mixed-wet rock was less than that obtained under water-wet conditions. We offer explanations for these observations based on our understanding of the pore-scale interactions and mechanisms, the distribution of fluid phases, and their spreading behavior. The results help us better understand the impact of some of the important parameters pertinent to k r and its hysteresis, especially in very low IFT gas/oil systems and mixed-wet rocks. Understanding these effects and behavior is important for the improved prediction of the performance of gas injection and water-alternating-gas (WAG) injection in oil reservoirs.

Optimization of Miscible CO2 Water-Alternating-Gas Injection in the Bakken Formation

“…Two sandstone reservoir core plugs were placed in series inside the Dean−Stark extractor and cleaned with toluene, methanol, and chloroform in sequence to remove hydrocarbons, salts, and clays, respectively. After the two sandstone reservoir core plugs were cleaned and dried, they were assembled in series in a horizontally placed 2.46 C 28 0.43 C 3 1.09 C 29 0.35 C 4 4.55 C 30 0.29 C 5 7.13 C 31 0.28 C 6 9.56 C 32 0.27 C 7 11.73 C 33 0.17 C 8 16.14 C 34 0.17 C 9 5.46 C 35 0.19 C 10 6.07 C 36 0.13 C 11 4.82 C 37 0.12 C 12 4.16 C 38 0.12 C 13 3.67 C 39 0.11 C 14 2.93 C 40 0.11 C 15 2.83 C 41 0.10 C 16 2.19 C 42 0.06 C 17 1.93 C 43 0.06 C 18 1.78 C 44 0.06 C 19 1 coreholder and vacuumed for 24 h. Then the synthetic brine was injected to measure the porosity of the composite reservoir core plugs. Afterward, the synthetic brine was injected at different volume flow rates (q brine = 0.01−0.05 cm 3 /min) to measure the absolute permeability of the composite reservoir core plugs.…”

A Comparison Study on Huff-n-Puff Gas Injection and Chemical Relative Permeability Modification to Mitigate Condensate Blocking in Fractured Shale Gas Condensate Reservoirs

“…Although the surfactant in case#3 may not exist, the results of case#3 give us an idea of how much more oil and gas would be produced if relative permeability curve is greatly altered. As mentioned earlier, studies in the literature show that the exponent n o cannot approach 1 even at a very low IFT (Fatemi & Sohrabi, 2013). Therefore, the exponent n o in three cases above is 3 or more.…”

“…In other words, the relative permeability exponent n p approaches 1 as capillary number increases. However, the results of the core flood experiments by Fatemi and Sohrabi (Fatemi & Sohrabi, 2013) show that, as a fluid system approaches miscibility, only for the non-wetting phase (gas) in the drainage direction, relative permeability present linear behavior and becomes straight line. For the wetting phase (oil) and the non-wetting phase in the imbibition direction, significant deviation of relative permeability from straight line is observed even at a very low IFT of 0.04mN m -1 .…”

Miscible CO2 Water-Alternating-Gas (CO2-WAG) Injection in a Tight Oil Formation

“…A total of 59 WAG injection field applications were reviewed by Christensen et al (2001), 24 projects of which were miscible CO 2 -WAG injection. Most CO 2 -WAG injection projects had larger oil RFs than waterflooding projects by at least 5-10%.There are a number of laboratory studies (Wang, 1980;Fatemi and Sohrabi, 2013;Kulkarni and Rao, 2005) and numerical simulations (Spiteri and Juanes, 2006; Fatemi et al, 2012) to examine some key parameters that determine the performance of WAG injection. These parameters include WAG slug size, WAG slug ratio, and fluid injection sequence in each cycle.…”

“…There are a number of laboratory studies (Wang, 1980;Fatemi and Sohrabi, 2013;Kulkarni and Rao, 2005) and numerical simulations (Spiteri and Juanes, 2006; Fatemi et al, 2012) to examine some key parameters that determine the performance of WAG injection. These parameters include WAG slug size, WAG slug ratio, and fluid injection sequence in each cycle.…”