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Since shale matrix has very low permeability, conventional reservoir simulators often do not accurately estimate the mass exchange between matrix and fractures. To evaluate the effect of water injection on the oil recovery, the mass transport in the reservoir at different scales should be modeled accurately. These issues have motivated us to evaluate the contribution of low salinity water injection on oil recovery in liquid-rich unconventional reservoirs accounting the effects of salinity, fluid type, shale swelling, and wettability alteration.
In this research, a phenomenological model was formulated to compute the mass transfer mass exchange between the rock matrix and the fractures. This mass transport model was validated using experimental data. A shale-swelling model was also derived to account for the swelling effect on the permeability and porosity by solving the coupled geomechanics and mass transport models. The coupled model was solved for every matrix blocks within the reservoir-scale model to evaluate the overall effect of salt concentration, shale swelling, and wettability alteration on the mass exchange between fractures and shale matrix. The reservoir-scale determines phase pressure, saturation, solute concentration, and liquid production.
The results show that swelling decreases matrix and fracture porosity, forcing the fluid out of the rock matrix and maintaining the pressure in fracture. However, matrix swelling reduces the permeability of the matrix and fractures, reducing oil recovery. Therefore, water injection is not recommended for formations with high swelling potential. The modified zipper pattern is recommended for enhanced oil recovery operations. The simulation results also suggested that higher density of hydraulic fractures increase oil recovery.
Recent research studies suggest the use of low salinity waterflooding, chemical flooding, CO2 injection, and gas injection for improving the recovery in shale oil reservoirs (Morsy et al. 2013, Chen 2013, Nguyen et al. 2014, Sheng 2015, He et al. 2015). However, we are currently using conventional models implemented in conventional simulators to evaluate the potential of each method. Further research on the mass transport mechanisms and modeling at various scales should be conducted to make any quantitative recommendations. Hence, modeling the mass transport in shale oil reservoirs and evaluating the overall effect of different factors on water injection enhanced oil recovery (EOR) is the focus of this study. A multi-scale reservoir model with a better evaluation of the mass exchange between the fractures and the rock matrix enables the investigation of the low salinity water injection on oil recovery in liquid-rich shale reservoirs.
Fakcharoenphol, Perapon (Colorado School of Mines) | Torcuk, Mehmet (Colorado School of Mines) | Bertoncello, Antoine (Hess Corporation) | Kazemi, Hossein (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines) | Wallace, Jon (Hess Corporation) | Honarpour, Matt (Hess Corporation)
Abstract Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model. The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period.
Fakher, Sherif (Missouri University of Science and Technology) | Elgahawy, Youssef (University of Calgary) | Abdelaal, Hesham (University of Lisbon) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.
Shi, Juntai (SPE, China University of Petroleum at Beijing) | Zhang, Lei (Research Institute of Yanchang Petroleum Grouop Co. LTD) | Li, Yuansheng (SPE, China University of Petroleum at Beijing) | Yu, Wei (The University of Texas at Austin) | He, Xiangnan (SPE, China University of Petroleum at Beijing) | Liu, Ning (SPE, China University of Petroleum at Beijing) | Li, Xiangfang (SPE, China University of Petroleum at Beijing) | Wang, Tao (Research Institute of Yanchang Petroleum Grouop Co. LTD)
Abstract The transport mechanism of gas moving through matrix pores is the bottleneck of conquering the difficulties in shale gas development. The matrix pores can be divided into organic and inorganic matrix pores. The transport mechanism of shale gas in organic and inorganic matrix pores is different. However, the present gas transport model only focused on the gas transport in organic matrix pores, in addition, the impact of organic and inorganic mass ratio has been largely neglected by shale gas transport models in the literature, leading to an unclear recognition of shale gas production discipline and large derivation between prediction results by the present models and actual performance of shale gas wells. In this paper, both the pore size distribution and water distribution in shale matrix pores are investigated. Furthermore, a new diffusion-slippage-flow model in combination with the gas transport mechanism is proposed. Also, the organic content effect is considered and the range of Knudsen number is quantified. Finally, a gas production model based on this gas transport mechanism is derived and employed to reveal the discipline of shale gas production. The preliminary results illustrate that Knudsen diffusion is not suitable for shale gas reservoirs. This is because Knudsen number is generally less than 10, especially for such shale gas reservoirs with higher initial reservoir pressure. Gas moving through shale matrix pores to fractures is mainly divided into two forms: in organic matrix pores, both slip effect and transition diffusion mechanism are dominant; in inorganic matrix pores, the gas-water two-phase flow controls the gas transport mechanism because of the presence of water in these pores. The efforts of this work will provide a more accurate technique for forecasting shale gas production, and also give some insights into scientific evidence to the rational development of shale gas reservoirs.
Shale gas is a major component of natural-gas supply in the United States. Multistage-fractured horizontal wells significantly improve the production performance of ultralow-permeability shale-gas reservoirs. Researchers have believed that shale-gas-production simulations should take into account the complex-flow behaviors in both fractures and the matrix. However, multiple physics applied on the matrix are generally incomplete in previous studies. In this study, we considered the comprehensive physics that occurred in the matrix including the effective stress, slip flow/pore diffusion, adsorption/desorption, and surface diffusion, as well as the dynamic properties of fractures. We investigated the importance of these features of the physics separately and in an integrated fashion by step-by-step production simulations. Afterward, comprehensive sensitivity analysis was performed with regard to stress dependency of the matrix and fractures. This work shows that natural-fracture spacing is the most prominent factor affecting shale-gas-reservoir performance. The work highlights the importance to gas recovery of mechanical squeezing of the pore volume by the effective stress. Surface diffusion might be essential for gas recovery that depends on surface-diffusivity values. Slip flow and pore diffusion do not significantly contribute to gas recovery even though they increase gas apparent permeability under low pressures.