The primary oil recovery in the Bakken Petroleum System is still small, with a range of 5% to 12% of the original oil in place (OOIP). This study aims to investigate the potential and the performance of CO2 injection with HnP on the recovery factor (RF) in Upper Three Forks (UTF) and Middle Three Forks (MTF) formations, Sanish Field, Williston Basin, North Dakota (ND). In order to achieve this purpose, a series of laboratory experiments were applied. Different parameters were considered to understand the mechanisms of HnP CO2-EOR, including the pressure of injection above and under the minimum miscibility pressure (MMP), the effect of soaking time on production, and several injection cycles to maximize the oil recovery. Then a comparison of the performance of CO2-EOR with ethane (C2) and propane (C3) under the same operating condition to evaluate the feasibility of different gases in the HnP approach. In addition, X-ray diffraction mineral analysis (XRD) was performed on four samples taken from UTF and MTF to determine the mineral composition in both formations. The results showed that the most recoverable formation was UTF with 56% of RF during the first cycle, while MTF showed only 37%. Increasing the number of cycling from one to four cycles showed that RF increased up to 88% and 75% in UTF and MTF, respectively. In addition, injection pressure seems to have a significant effect on RF in both formations, where the results showed that increasing the pressure from 800 Psi to 3600 Psi improved RF from 15% and 16% to 56% and 37% in UTF and MTF, respectively. Moreover, increasing the soaking time from 4 hrs to 48 hrs, RF increased from 37% and 25% to 72% and 39% in UTF and MTF, respectively. The results from comparison of different gases injections showed that, with injection pressures of 3600 Psi and soaking time of 24 hrs, ethane was the most effective gas in both formations, followed by propane and CO2, respectively.
The Bakken Petroleum System in the Williston Basin consists of three main members: Upper Bakken Shale (UB), Middle Bakken (MB), and Lower Bakken Shale (LB). The Middle Bakken is a calcareous siltstone and fine-grained sandstone which is a proven reservoir within the Williston Basin. Injection of Supercritical CO2 (ScCO2) may cause changes in the elastic behavior of the rock and therefore may reactivate the fault in the Bakken Formation. This research aims at studying the changes in the MB mechanical properties when flooded with ScCO2 for 30 days, and to quantify the physical and chemical effects of ScCO2 saturation on the mineralogy composition and fluid properties of the formation. This will be achieved using different rock physics models before and after ScCO2 injection. Two different samples were taken from MB clastic and carbonate portions of well 24123 in McKenzie County. X-Ray Diffraction (XRD) analysis was applied on two samples pre- and post-CO2 saturation. The results of post-CO2 modeling resulted in a decrease of densities and elastic properties of both lithologies at different rates. Only change in mineralogy and fluid properties were considered for the post-CO2 injection modeling.
The velocity-porosity relationship depends on many factors such as grain shape, sorting, chemical composition, and diagenesis processes. Fluids always occupy the pore space and pore shape plays a significant role in rock stiffness. The Bakken Petroleum System (BPS) in the Williston Basin, North Dakota, consists of the Bakken formation and three folks reservoirs. Bakken formation is divided into three members: Upper Bakken (UB), Lower Bakken (LB), and Middle Bakken (MB), while Three Forks (TF) formation divided into five different units. Although clastic formation’s pores spaces are homogeneous, carbonates present pores heterogeneity which makes their elastic properties estimation complex. This heterogeneity is represented by different pore shapes captured from thin sections, where the aspect ratio (a) defines multiple pore types such as cracks, intergranular, and moldic pores. Furthermore, the pore filling material is a mixture of gas, oil, water, and kerogen in organic-rich shale. This study aims to analyze the effect of mineral composition, pore shape, and fluid type on rock properties of the BPS using various rock physics models. Our results showed that both compressional and shear velocities decreased for all fluid types. We also observed that filling pores with different fluids affect the elastic properties differently, based on their pore geometry, porosity, and lithology.
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