There is tremendous potential for shale oil reservoirs, such as the Bakken Formation, Eagle Ford and Niobrara to have a lasting impact on the U.S energy situation due to the multi-billion barrel resource base that these formations contain. Horizontal drilling and multi-stage hydraulic fracturing technologies have allowed significant oil to be produced in the Elm Coulee Field in Bakken Formation; however, the primary recovery factors are still less than 10%, which means enhanced oil recovery (EOR) methods need to become the next big push in shale oil research. Miscible gas injection may become the most effective EOR method in such low permeability fields, because conventional water flooding may result in extremely low injectivity. This work expands on the previous research that showed miscible gas injection may be a possible solution for the Elm Coulee Field. All the wells in that study have longitudinal hydraulic fractures; whereas today, most wells have the multi-transverse fractures. The significance of this research is to evaluate the reservoir performance of the miscible gas flooding with different hydraulic fracture orientations; longitudinal hydraulic fracture orientation and transverse hydraulic fracture orientation, and recommends the best hydraulic fracture orientation. In the thesis, separate numerical simulation models with multi-transverse hydraulic fractures and longitudinal hydraulic fractures have been built and the results are compared in the flow simulator Eclipse. Miscible gas injection can increase the recovery factor (RF) from less than 10% in the primary production to above 25% for both types of hydraulic fracture orientation. Two different gridding methods were used in this work. In the uniform gridding method, the transverse fracture case always performs better than the longitudinal fracture in both the primary and secondary production. However, in the local grid refinement (LGR) gridding method, the longitudinal fracture leads to a higher RF than the transverse fracture in miscible gas injection due to its late breakthrough time and similar "piston displacement". Also, the utilization factor, which is the ratio of the total injected solvent over the total oil produced, indicates that the longitudinal fracture is more effective than the transverse fracture case. Four different permeability values for the upper Bakken, ranging from 2.5x10-1 md to 2.5x10-4 md, have been chosen to compare, and the results indicate that the degree of the upper Bakken permeability impact decreases at lower permeability values. Also, several Middle Dolomite permeability cases are built and the comparison shows that if the permeability values increase from 0.01 md to 0.02 md, the RF increases more than 5%. From the hydraulic facture permeability sensitivity analysis, 100 md is considered as the boundary of the finite fracture and infinite fracture for this field. If the hydraulic fracture permeability value is less than 100 md, the RF and oil production increase significantly as the permeability increases. However, if the permeability is more than 100 md, the reservoir performance will not increase largely as the permeability increases. The bottom hole pressure (BHP) shows that if the BHP increases from 3500 psi to 4700 psi, the RF decreases from 8% to less than 3% for the primary production, and for miscible gas injection, the RF decreases from 28% to 19%. The results of all the flow simulation models are discussed and analyzed in Chapter 4 and Chapter 5. This work, which simulates the miscible gas injection procedure by using the flow simulator Eclipse, forms the foundation to begin understanding how to best perform the miscible gas injection EOR and optimize the best hydraulic fracture orientation in the Elm Coulee Field in the Bakken Formation.
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