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This research investigated adsorptive deacidification of lipid feedstocks using Dowex monosphere MR-450 UPW mixed-bed resin (Sigma-Aldrich, St. Louis, MO). The impact of temperature, mixing and feedstock moisture content on deacidification kinetics is reported. Resin reusability and deacidification of multiple feedstocks was examined. Our results demonstrated that deacidification using the resin followed Lagergren's pseudo first-order reaction kinetics with a rate constant of 1.352/min under the most favorable reaction conditions (50C, 0% moisture content and 550 rpm mixing rate). Gibb's free energy of the reaction increased from −2.81 kJ/mol at 298 K to −12.17 kJ/mol at 323 K, demonstrating the impact of temperature on deacidification. Resin regeneration with methanolbased rinses resulted in at least 40% feedstock deacidification after three wash cycles. Collectively, our research results demonstrate the promise of using heterogeneous gel-type resins for deacidification of a wide range of feedstocks and edible oils with a high percentage of free fatty acid and/or impurities. PRACTICAL APPLICATIONSDowex monosphere MR-450 UPW mixed-bed gelular ion-exchange resin is effectively used for adsorptive deacidification of high fatty acid oils in the absence of alcohol at low reaction temperatures (<60C). The ion-exchange resin surfaces are regenerated with solvent washing and reused for deacidification over multiple cycles.

Summary Researchers from both industry and academia have intensively studied tight oil resources in the past decade since the successful development of Bakken Shale and Eagle Ford Shale, and have made tremendous progress. It has been recognized that locating the sweet spots in the regionally pervasive plays is of great significance. However, we are still struggling to determine whether the dominant control on shale-well productivity is geologic or technical. Given certain geological properties, what is the best completion strategy? Most of the previous studies either analyze the completion data alone or divide the entire play into different data clusters by map coordinates and depth, which might neglect the heterogeneity in thickness and reservoir-quality parameters. In our study, we first conducted stratigraphic and petrophysical analyses, using the regional variation in depth, thickness, porosity, and water saturation to capture the regional heterogeneity in the Bakken Shale petroleum system. We selected approximately 2,000 horizontal wells, targeting the Middle Bakken Formation with detailed completion records and initial production dates during 2013 and 2014. Completion data inputs include normalized stage length (NSL), stage counts, normalized volume of fluid (NVF), and normalized volume of proppant (NVP). We investigated the relationship between the geological and completion features, and its effect on the first year of production. Then, we built a neural-network model to identify the relationship between the first-year oil production and the selected features. We separated the data into three sets for training, validation, and testing. After we trained the model using the training and validation set, we tested the model to estimate its robustness. Through sensitivity analysis, we demonstrated how the completion parameters combined with geological input would affect the production. The developed technique provides a method to identify the best well location, understand the effectiveness of the completion strategy, and predict the well production. Although the data used came from wells in the Bakken Shale, the methodology applies in a similar way to other tight oil plays.

In general, hydraulic fractures propagate perpendicular to the horizontal well axis whenever the drilling direction is parallel to the principal minimum stress plane. However, operators frequently drill horizontal wells parallel to lease boundaries resulting in slanted hydraulic fracture planes at angles less than 90 degrees from the well axis. This study provides a model for the inclined fracture case. It applies and further extends the unified fracture design approach for rectangular drainage areas, relating the dimensionless proppant number to the maximum productivity index in pseudo-steady state conditions. When simulating flow in shale reservoirs, the stimulated shale volume was represented as a rectangular drainage area that varies with changing angle, but preserves total area. Similarly, fracture length and width varies with changing angle, but total propped fracture volume stays constant. Results show that for any given set of reservoir and proppant properties along with a given proppant mass, as long as the created fractures drain the same stimulated rock volume, there exists a well direction resulting in maximized well productivity that is not necessarily parallel to the minimum stress direction. In addition, results yield two main correlations. The first one relates the optimal fracture angle to proppant number, for a given ratio of well spacing to primary-fracture spacing. In this way, operators can choose the drilling azimuth that would maximize production. The second correlation determines the optimal ratio of well spacing to primary-fracture spacing as a function of proppant number for a given fracture angle. This can be applied when selecting the optimum number of fracture stages given a well spacing plan and fracture angle. Two case studies show the application of these findings. In the end, this work provides a simple framework for well design incorporating slanted hydraulic fractures.