The low recovery and high oil volume remaining in shale oil reservoirs are a strong motivation to investigate the application of enhanced oil recovery methods in these reservoirs. This paper presents the potential of applying cyclic CO 2 injection to improve the recovery factors of shale oil reservoirs. Cyclic CO 2 injection could be an effective technique to improve the oil recovery of this type of reservoirs for several reasons. It is a single-well process; well-to-well connectivity is not required, the hydraulic and natural fractures provide a large contact area for the injected gas to penetrate and diffuse into the lowpermeability matrix; and the payback period of the cyclic CO 2 injection process is short compared with the other flooding process. Very limited numerical and laboratory studies are available to study the feasibility of CO 2 huff-n-puff for shale oil reservoirs. Latest numerical studies have revealed that CO 2 huff-n-puff technique could be an effective method to increase recovery factors of shale oil reservoirs. In order to support the numerical studies results, a laboratory study was conducted using shale cores from Mancos and Eagle Ford. The aim of this study is to evaluate the potential of cyclic CO 2 injection. Many design parameters such as soaking period, soaking pressure, and numbers of cycles were considered to evaluate the feasibility of cyclic CO 2 injection. The laboratory results indicate that cyclic CO 2 injection improved recovery of shale oil cores from 33% to 85% depending on the shale core type and the other operating parameters. These results have shown that cyclic CO 2 injection is a promising method to improve the recovery of shale oil reservoirs. Also this study aided to develop a better understanding of the performance of cyclic CO 2 in shale oil reservoirs.

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.

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Experimental and numerical studies have demonstrated that there is great potential of enhancing the oil recovery from tight formations. This study investigated the effect of acid matrix treatment by applying gas flooding on the core samples before and after the treatment. The aim of the acid stimulation treatment was to improve the low-permeability of the cores. Four core samples (0.5 in, 1.0 in, 1.5 in, and 2.0 in) from an outcrop of the Eagle Ford formation were used in this study. Permeability was measured before and after the acid treatment. The cores were CT-scanned to identify natural fractures. Different gas injection pressures were used to study the oil recovery and the time needed to penetrate through core samples. Furthermore, a solubility test was applied to identify the optimal acid concentration. The cores were re-scanned after the acid flooding treatments to detect any change. Gas flooding was applied to acidized core samples to detect changes in penetration time and recovery factor. A solubility test demonstrated that 15% of HCL was the optimal acid concentration for the Eagle Ford formation. The study showed the porosity, permeability, recovery factor, and penetration time before and after the acidizing treatment. Permeability was enhanced from 1.04 nanodarcies to 2.10 microdarcies. Furthermore, the study showed the effect of core length on penetration rate (in/min) of gas flooding and the recovery factor at each injecting pressure. The penetration time in this study varied from 207 to 112 minutes/inch when the injecting pressure increased from 1500 to 2500 psi. After acidizing, however, the penetration rate decreased to 8.4 minutes/inch using flooding of 300 psi. The CT scan showed improvement of the micro fracture width.

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.