High Pressure Tertiary-CO2 Flooding in a Fractured Chalk Reservoir (2017)

Abstract The purpose of this study is to present the numerical and experimental evaluation of the tertiary-CO2 flooding (CF) at high operating pressure and reservoir temperature. In this study, water flooding is followed by CO2 injection into an outcrop chalk core with a centralized fracture. Our validated numerical models reproduce the result of core flooding experiments. In addition, we upscale the simulation model and investigate the scale dependency of the diffusion mechanism in a larger matrix-fracture domain. The experiments used an outcrop core which is vertically placed in the core-holder with the total length of 28 cm and the diameter of 12.3 cm. The axial "fracture" is represented by a centralized hole with the diameter of 2.2 cm. We utilize the Wood's Metal technique to initially saturate the chalk core with the North-Sea-Chalk-Field (NSCF) live oil. The core sample is aged to restore the chalk wettability at the operating conditions. Then, the water flooding (WF) is performed by injecting brine from the bottom of the fracture and producing the oil from the top. After no additional produced oil is observed, the WF is stopped. A "shut-in" period follows, which allows preparing the rig for tertiary-CO2 flooding. CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions at 300 bara (4351 psia) and 110 ºC, which is higher than the typical NSCF reservoir conditions (258 bara and 110 ºC). This allows us to investigate the efficiency of the tertiary-CF at a higher operating pressure condition. We employ a compositional reservoir simulation with a developed equation of state (EOS) to model the experiment. An automated history matching procedure is developed to match the experimental results. The modeling workflow is capable of taking into account the significant vaporization effect observed during CF when the rich-CO2 enters the three-phase separator. An upscaling study is conducted to evaluate the performance of CF in a single and multiple fracture-matrix systems. Moreover, the accuracy of dual porosity models is tested against the reference single porosity model. We accurately model the WF experiment through tuning the oil-water capillary pressure and relative permeability data. The numerical model is capable of reproducing the CF lab results by employing the best match multi-component diffusion coefficients. Moreover, we successfully model the excessive water production during CO2 injection by taking into account the hysteresis effect in water-oil capillary pressure and relative permeability. Comparing these results with our previous work at lower reservoir pressure shows the positive effect of pressure on increasing the efficiency of the tertiary-CF in recovering more oil from a matrix-fracture system. Also, the tuned capillary pressure and relative permeability during WF indicate an active imbibition drive and a strongly water-wet system. In the upscaling work, we consider the effect of several key parameters on oil recovery; e.g. matrix block size, fracture spacing, CO2 injection rate, gravity drainage, vaporization and the diffusion. The results show that the mass transport is mainly dominated by diffusion in the lab scale even though this is not the case in the large matrix block size. Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system. We also provide some important inputs that are necessary for upscaling tertiary-CF from a lab-scale into a field-scale reservoir model.