This paper discusses the methodology necessary for lithology identification and petrophysical analysis of an unconventional reservoir in Williston Basin. The scope of the work is done on a producing oilfield in the North Dakota portion of the basin. Well logs from 45 wells in Blue Buttes Field were analyzed, mainly focusing on the Middle Bakken section of the Bakken Formation. Reservoir properties, such as permeability, effective porosity, shale volume, and saturation were determined using a set of commercial software. Several methods for analyzing each property were tried, the results were compared and the best method was picked that matched the core analysis such as the XRD scanning. The results of this study can help with a decision regarding the further development of the reservoir specifically in the Blue Buttes Field or to improve the understanding of various properties from the Middle Bakken. The procedures presented in this paper will help to establish a workflow for similar studies in other unconventional reservoirs in the future. This case study also helps better understand the lithology and rock properties of the Middle Bakken.

The objective of this study is to perform geological, petrophysical, geomechanical, decline curve, and economic analyses; a numerical reservoir simulation; and lastly a well and facility design for the Mission Canyon Formation of the Charlson Field of North Dakota. Essentially, the goal is to perform a broad start-to-finish analysis of the Charlson Field, while also determining the feasibility of a different development plan than what was used. It is important to note that the study is on a look-back basis as the field is mature and depleted. Geological and petrophysical analyses were performed using available well log and core data. A complete geomechanical and wellbore stability study was done as well. The well and facility design consists of casing, cementing, and separator design. These designs were established using historical designs, literature, and calculations. Numerical reservoir simulation was performed using simulation software and data obtained from the geological and petrophysical analysis. Decline curve analysis was performed using field production data. Lastly, economic analysis used historical oil prices, well cost data, and reservoir simulation production data. The results of the geological and petrophysical analyses helped to better understand the lithology, geology, and petrology of the Charlson Field. These results refined the area of study to areas of high production capability and obtained characteristics to use later in the study. The geomechanical analysis provided a Mechanical Earth Model, and a mud weight window that could be used to create drilling mud, and casing designs. The well design portion delivered casing and cement designs, that along with drilling mud designs created using the mud weight window, could have possibly helped alleviate casing failures seen in the field. The separator design provided an optimized separator system and operational conditions. The numerical reservoir simulation and decline curve analysis both provided production estimates for a development plan. The economic analysis was performed to determine the economic feasibility of the proposed development plan. The study determined that drilling another well in 1984 during the infill drilling of a separate well could have generated ~$18 Million net present value, with a rate of return of 18%. In addition, the well design could have helped alleviate casing failures in the Charlson Field. With the above conclusions, it is easy to see that even with the limited data used in this project, it is imperative to manage data for optimal results in any development.

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Minimizing the costs and risks of drilling and achieving a maximum production rate in tight shale formations is technically and economically challenging. An in-depth investigation of the Geomechanical behavior of the reservoir, including rock elastic and strength properties, and the in-situ stresses, which leads to Mechanical Earth Model (MEM), is inevitable. In this paper, a new concept of estimating fracturing potential by Fracture Mechanical Earth Model (FMEM) is presented. We analyzed the state of In-situ stresses, formation Properties, and type of instabilities that occur around the trajectory of the wellbore by acquiring anisotropic poroelastic relationships to incorporate pore pressure and stresses changes in the field more accurately. In the next step, we determined safe mud weight window to avoid shear and tensile failure during drilling and mitigating other wellbore instabilities issues by controlling the sub surface parameters. Frack-ability, brittleness, and ductility of rock are formation stress dependent which varies from region to region, not all the rocks respond in the same manner to fracturing job. To study the fracking potential of a particular formation, along with data required for MEM, rock Brittleness properties, which govern fracture kinematic Properties (initiation, propagation, closure, toughness) should be studied as well. To do so, we used Well logs to create (FMEM) to predict fracking potential. Brittleness was extracted from the Geomechanical and Mineralogical analysis. In the next step, we showed Total Organic Carbon (TOC) present in the matrix affects stiffness and frack ability of rocks. (TOC) Obtained from Log Based analysis was calibrated with TOC from Laboratory experiments on core Samples. The constructed FMEM revealed how changes in pore pressure, in-situ stress properties, and physiochemical of the shale could hugely influence the drilling operations in the field. The Constructed FMEM revealed sweet spots for Fracking from the field, which will be an input of paramount importance in planning phases of well which will have an immense impact on Future Deviated Drilling and Hydraulic Fracturing, studies.